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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES AND EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1994
COMMISSION IRS EMPLOYER
FILE STATE OF IDENTIFICATION
NUMBER REGISTRANT INCORPORATION NUMBER
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1-7810 Energen Corporation Alabama 63-0757759
2-38960 Alabama Gas Corporation Alabama 63-0022000
2101 Sixth Avenue North
Birmingham, Alabama 35203
(205) 326-2700
Securities Registered Pursuant to Section 12(b) of the Act:
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TITLE OF EACH CLASS EXCHANGE ON WHICH REGISTERED
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Energen Corporation Common Stock, $0.01 par value New York Stock Exchange
Energen Corporation Preferred Stock Purchase Rights New York Stock Exchange
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Securities Registered Pursuant to Section 12(g) of the Act: NONE
Indicate by a check mark whether registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities and Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports) and (2) have been subject to
such filing requirements for the past 90 days. YES X NO
----- -----
Indicate by a check mark if disclosure of delinquent files pursuant to Item 405
of Regulation S-K (Section 229.405 of this chapter) is not contained herein and
will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. ( )
Aggregate market value of the voting stock held by non-affiliates of the
registrants as of November 15, 1994:
Energen Corporation $233,414,500
Indicate number of shares outstanding of each of the registrant's classes of
common stock as of November 15, 1994:
Energen Corporation 10,919,977 shares
Alabama Gas Corporation 1,972,052 shares
DOCUMENTS INCORPORATED BY REFERENCE
- - Energen Corporation Proxy Statement to be filed on or about December
15, 1994 (Part III, Item 10-13)
- - Portions of Energen Corporation 1994 Annual Report to Stockholders are
incorporated by reference into Part II, Items 5, 6, 7, and 8 of this
report
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ENERGEN CORPORATION
1994 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
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PAGE
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PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . 8
PART II
Item 5. Market for Registrant's Common Stock and Related Stockholder Matters . . . . 11
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . 12
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . 12
PART III
Item 10. Directors and Executive Officers of the Registrants . . . . . . . . . . . . . 12
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Item 12. Security Ownership of Certain Beneficial Owners and Management . . . . . . . 13
Item 13. Certain Relationships and Related Transactions . . . . . . . . . . . . . . . 13
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K . . . . . . 13
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This Form 10-K is filed on behalf of Energen Corporation (Energen or the
Company) and Alabama Gas Corporation (Alagasco).
PART I
ITEM 1. BUSINESS
GENERAL
Energen is a diversified energy holding company engaged primarily in the
distribution, exploration, and production of natural gas.
Energen was incorporated in Alabama in 1978 in connection with the
reorganization of its largest subsidiary, Alagasco. Alagasco was formed in
1948 by the merger of Alabama Gas Company into Birmingham Gas Company, the
predecessors of which had been in existence since the late 1800's. Alagasco
became a public company in 1953.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
The information required by this item is incorporated by reference from Note 13
to the Consolidated Financial Statements of the 1994 Annual Report to
Stockholders, and is attached herein as Part 1V, Item 14, Exhibit 13.
NARRATIVE DESCRIPTION OF BUSINESS
- - NATURAL GAS DISTRIBUTION
GENERAL: Alagasco, Energen's principal subsidiary, is the largest
natural gas distribution utility in the State of Alabama. Alagasco
purchases natural gas through interstate and intrastate suppliers and
distributes the purchased gas through its distribution facilities for
sale to residential, commercial, industrial and other end-users of
natural gas. Alagasco also provides transportation services to
industrial and commercial customers located on its distribution
system. These transportation customers, acting on their own or using
Alagasco as their agent, purchase gas directly from producers or other
suppliers and arrange for delivery of the gas into the Alagasco
distribution system. Alagasco then charges a fee to transport this
customer-owned gas through its distribution system to the customer's
facility.
Alagasco's service territory is located primarily in central and north
Alabama and includes over 175 communities in 30 counties. Birmingham,
the largest city in Alabama, and Montgomery, the state capital, are
served by Alagasco. The counties in which Alagasco provides service
have an aggregate area of more than 22,000 square miles and include
the service territories of various municipal gas distribution systems.
The aggregate population of the counties served by Alagasco is
estimated to be 2.4 million. During 1994 Alagasco served an average
of 402,531 residential customers, 32,563 small commercial and
industrial customers, and 43 large commercial and industrial
customers. The Alagasco distribution system includes approximately
8,500 miles of main, more than 9,300 miles of service lines,
odorization and regulation facilities, and customer meters. Alagasco
also operates two liquefied natural gas facilities which it uses to
meet peak demands.
APSC REGULATION: As a public utility in the state of Alabama,
Alagasco is subject to regulation by the Alabama Public Service
Commission (APSC), which has adopted several innovative approaches to
rate regulation, including Alabama's Rate Stabilization and
Equalization (RSE) rate-setting process. Implemented in 1983 and
modified in 1985, 1987, and 1990, RSE replaces the traditional utility
rate case
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with APSC-monitored periodic rate adjustments presently designed to
give Alagasco the opportunity to earn an average return on equity
(ROE) at its fiscal year-end within a specified range. Under
Alagasco's current RSE order, which became effective December 1990,
Alagasco's allowed ROE range is 13.15 percent to 13.65 percent. The
APSC conducts quarterly reviews to determine, based on Alagasco's
budget and fiscal year-to-date performance, whether Alagasco's
projected ROE for the fiscal year will be within the allowed range.
Reductions in rates can be made quarterly to bring the projected ROE
within the allowed range. Increases, however, are permitted only once
each fiscal year effective on December 1, and cannot exceed 4 percent
of prior-year revenues.
RSE limits Alagasco's equity upon which a return is permitted to 60
percent of total capitalization and provides for a cost control
measure designed to monitor Alagasco's operations and maintenance (O &
M) expense. If increases in O & M expense per customer fall within
1.25 percent above or below the Consumer Price Index for all Urban
Customers (index range), no adjustment is required. If, however,
increases in O & M expense per customer exceed the index range,
three-fourths of the difference is returned to customers. To the
extent increases in O & M expense per customer are less than the index
range, Alagasco will benefit by one-half of the difference through
future rate adjustments.
Under its terms, Alagasco's current RSE order continues until, after
notice to Alagasco, the APSC votes to either modify or discontinue its
operation. On October 4, 1993, the APSC unanimously voted to defer
review of the current RSE order until such time as certain hearings
mandated by the Energy Policy Act of 1992 (Energy Act) in connection
with integrated resource planning and demand side management programs
are completed. The Energy Act proceedings are expected to conclude
during 1995 at which time it is expected that the Commission will
begin reviewing Alagasco's RSE. No time table for review has yet been
established.
FERC REGULATION: Alagasco's interstate pipeline suppliers, Southern
Natural Gas Company (Southern) and Transcontinental Gas Pipeline
Corporation (Transco), are subject to regulation by the Federal Energy
Regulatory Commission (FERC). Among other things, FERC regulates the
character of services that Southern and Transco can offer and the
rates and fees they can charge Alagasco and other customers for gas
sales and transportation; thus, FERC can directly affect Alagasco's
services and operating expenses.
Effective November 1, 1993, Southern substantially restructured its
services pursuant to FERC Order 636 which required interstate
pipelines to eliminate their role as a merchant of a "bundled" sales
service; Transco unbundled its services prior to fiscal 1994. In place
of the sales service formerly offered, Southern now provides unbundled
contract storage service and various transportation services. As a
result of the shift from merchant to transporter, Southern has and
will incur transition costs, including the cost of buy-outs or
buy-downs of long-term gas supply contracts. These costs, referred to
as Gas Supply Realignment, or GSR, costs are recovered primarily by
Southern from its firm customers, subject to prudence and eligibility
review by FERC, in the form of a surcharge. Alagasco has received
approval from the APSC to pass through the GSR surcharge to Alagasco's
customers through the Gas Supply Adjustment (GSA) rider to Alagasco's
tariff.
In addition, Order 636 required pipelines to change the methodology
used to classify costs between the demand and commodity components for
purposes of cost allocation and rate design from the Modified Fixed
Variable (MFV) to the Straight Fixed Variable (SFV) methodology. The
SFV method recovers more of the pipeline's fixed costs through the
demand component of rates and causes cost shifts from customers with
relatively high load factors to customers with relatively low load
factors. Order 636 required that pipeline customers which were
negatively affected by the use of SFV, such as Alagasco, must be
provided mitigation measures to reduce the rate impact of
restructuring. In accordance with Southern's restructuring order,
Alagasco has been allowed to reduce its capacity demand during the
six-month off-peak period in order to limit the rate impact of the SFV
cost shift to less than 10 percent.
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Alagasco's GSA filing with the APSC, which became effective November
1, 1993, included all of the cost components for restructuring (GSR
costs, mitigation of SFV, lower commodity cost of gas, costs of
storage service, etc.). This adjustment to rates resulted in a modest
rate reduction.
Although Southern commenced its restructured services on November 1,
1993, there remain proceedings pending before FERC and the courts
challenging the Southern restructuring order as well as the Order 636
process generally.
GAS SUPPLY: The Alagasco distribution system is connected to and has
firm transportation contracts with two major interstate pipeline
systems--Southern and Transco. Effective November 1, 1993,
Alagasco's pre-Order 636 contract demand and firm transportation with
Southern converted to 250,924 Mcf (thousand cubic feet) per day of
No-Notice Firm Transportation service for a period of 15 years, 91,946
Mcf per day of Firm Transportation service for 15 years, and 50,000
Mcf per day of Firm Transportation for five years. Southern also
unbundled its existing storage capacity. Alagasco's pro rata share of
this storage is 12,426,687 Mcf. Alagasco has a maximum withdrawal
rate from storage of 250,924 Mcf per day and a maximum injection rate
into storage of 95,590 Mcf per day. The Transco firm transportation
contract, which expires in 2001, provides for maximum daily firm
transportation of up to 100,000 Mcf. Thus the Company has a peak day
firm interstate pipeline transportation capacity of 492,870 Mcf per
day.
Alagasco has replaced the sales service formerly provided by Southern
with purchases from various gas producers and marketers including
affiliates of Southern and Transco and from certain intrastate
producers including Basin Pipeline Corp., an Energen subsidiary.
Alagasco has contracts in place to purchase up to a total of 286,776
Mcf per day of firm supply, of which 271,946 is supported by firm
transportation on the Transco and Southern systems, 14,830 Mcf provides
redundant supply on the Southern system, and 30,000 Mcf is purchased
at the city gate from intrastate suppliers. This volume along with
Alagasco's maximum withdrawal from storage of 250,924 Mcf per day and
200,000 Mcf per day of liquefied natural gas peak shaving capacity
gives Alagasco a peak day firm supply of 722,870 Mcf per day. Alagasco
also utilizes the Southern and Transco pipeline systems to access spot
market gas in order to supplement its firm system supply and serve its
industrial transportation customers.
COMPETITION AND PRICING: The price of natural gas is a significant
marketing factor in the territory served by Alagasco; propane, coal
and fuel oil are readily available, and many major industrial
customers have the capability to switch to alternate fuels. In the
residential and small industrial and commercial markets, electricity
is the principal competitor.
Natural gas service available to Alagasco customers generally falls
into two categories -- interruptible and firm. Interruptible service
is contractually subject to interruption by Alagasco for various
reasons, the most common of which is curtailment of industrial
customers during periods of peak residential heating demand on the
Alagasco system. Firm service is generally not subject to
interruption and, therefore, is more expensive than interruptible
service. Firm service is generally provided to residential and small
commercial and industrial customers. Interruptible service is
generally provided to large commercial and industrial customers which
typically have the capacity to reduce consumption by adjusting their
production schedules or by switching to alternate fuels during periods
of interruption. Deliveries of sales and transportation gas totaled
97,531 MMcf (million cubic feet) in 1994.
Alagasco has a Competitive Fuel Clause as part of its rate tariff
which allows Alagasco to adjust large commercial and industrial prices
on a case-by-case basis to compete with either alternate fuels or
alternate sources of gas. The GSA rider to Alagasco's tariff
increases the rates paid by other customers to recover the reduction
in rates allowed under the Competitive Fuel Clause because the
retention of any customer, particularly large commercial and
industrial, benefits all customers by recovering a portion of the
system's fixed cost. During 1994 approximately 23.9 percent (12,582
MMcf) of Alagasco's deliveries of gas to large commercial and
industrial customers were made under the Competitive Fuel Clause.
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Alagasco also has a Transportation Tariff which allows the Company to
transport gas for customers rather than buying and reselling gas to
them. The Transportation Tariff is based on Alagasco's gas sales
profit margin so that Alagasco's net income is not affected whether it
transports or sells gas. The Transportation Tariff also may be
adjusted under the Competitive Fuel Clause. Of Alagasco's total large
commercial and industrial customer deliveries during 1994, 99.7
percent (37,678 MMcf) was from transportation of customer-owned gas.
GROWTH: Alagasco has supplemented traditional service area growth
with acquisitions of municipally-owned gas distribution systems.
Since 1985 Alagasco has acquired 19 such systems, including the
2,200-customer gas system of Alabaster purchased in early fiscal 1995.
More than 42,000 customers have been added through initial system
purchases and subsequent customer additions, as Alagasco has increased
the relatively low saturation rates in the acquired areas through a
variety of marketing efforts including: offering natural gas service
to propane customers already situated on the municipal system lines;
extending the acquired municipal system into nearby neighborhoods
which desire natural gas service; and marketing natural gas appliances
to existing and new customers. Approximately 80 municipal systems
remain in Alabama, and many are located in or near Alagasco's existing
service territory. The Company is optimistic that additional
acquisition opportunities will arise in the future.
Power generation is a possible avenue of future growth for Alagasco.
During 1994 Alagasco built a nine-mile pipeline to an Alabama Power
Company electric peaking plant in order to provide natural gas to nine
combustion turbine (CT) units scheduled to begin operation in 1995.
The CT units will generate electricity during periods of peak demand,
providing Alagasco with a new substantial summertime load.
WEATHER: Alagasco's gas distribution business is highly seasonal
since a material portion of Alagasco's total sales and delivery
volumes is to customers whose use varies depending upon temperature,
principally residential, small commercial and small industrial
customers. Alagasco's rate tariff includes a temperature adjustment
rider which is designed to mitigate the effect of departures from
normal temperature on Alagasco's earnings. The calculation is
performed monthly and adjustments are made to customer's bills in the
actual month the weather variation occurs.
ENVIRONMENTAL MATTERS: Alagasco is in the chain of title of eight
former manufactured gas plant sites, of which it still owns four, and
five manufactured gas distribution sites, of which it still owns one.
A preliminary investigation of the sites does not indicate the present
need for remediation activities. Management expects that, should
remediation of any such sites be required in the future, Alagasco's
share, if any, of such costs will not materially affect the results of
operations or financial condition of Alagasco.
- - OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES
Energen's oil and gas exploration and production activities are
conducted by its subsidiary, Taurus Exploration, Inc. (Taurus), and
involve the exploration for and the production of natural gas and oil
from conventional and nonconventional reservoirs. Taurus's 1994 oil
and gas production totaled 10.3 Bcf (with oil expressed in natural gas
equivalents), and the average sales price was $1.94 per Mcf
equivalent. Conventional oil and gas reserves of 42,261 MMcf
equivalents plus nonconventional gas reserves of 26,712 MMcf combine
for total oil and gas reserves at fiscal year-end of 68,973 MMcf
equivalents.
CONVENTIONAL: Taurus's conventional oil and gas strategy is to build
a foundation of low-risk, income- producing properties through
acquisitions and supplement its returns with exploration activities.
Taurus has agreements with PMC Reserve Acquisition Company and General
Atlantic Resources, Inc. which provide avenues for investment in
producing properties. Taurus is continuing to independently evaluate
other producing property acquisition opportunities. To help ensure a
continuing flow of exploratory prospects, during 1994 Taurus entered
into a multi-year joint venture with King Ranch and Holley Petroleum
Inc.
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which will utilize newly available 3-D seismic data. The new 3-D data
will provide coverage of more than 200 offshore Texas blocks,
representing approximately one million acres of potential leasehold.
Taurus's exploration activities are concentrated in the shallow waters
of the Gulf of Mexico. Four successful discoveries during 1994 added
reserves of 5.3 Bcf equivalents. Proved property acquisitions added
reserves of 1.7 Bcf equivalents.
NONCONVENTIONAL: Taurus's nonconventional gas strategy is to focus on
operating the large projects in which it has a small working interest
and operate for others; supplementing these activities, Taurus also
consults on an international basis. Taurus does not anticipate
additional major project development in the Black Warrior Basin, and
results of an internally generated, comprehensive evaluation of North
America for new coalbed methane exploration opportunities showed that
available opportunities do not meet Taurus's current risk profile.
Taurus does plan, however, to continue its operating and consulting
activities.
At September 30, 1994, Taurus had working interests in 441 coalbed
methane wells and royalty interests in an additional 216 wells, all
located in Alabama's Black Warrior Basin. Gas produced from these
wells through the year 2002 qualifies for the Section 29 tax credit
for producing fuel from nonconventional sources. Net decreases to
coalbed methane reserves in 1994 totaled 3.7 Bcf, and primarily
reflect the effects of lower prices as of September 30, 1994.
Taurus is the operator of more than 950 coalbed methane wells,
including wells in an existing project owned by TECO Coalbed Methane,
Inc., one of Taurus's coalbed methane associates in other projects.
Under the terms of the agreement, Taurus provides technical,
administrative and operating services and receives additional
compensation based on the project's profitability.
During 1994 Taurus signed a multi-year strategic alliance with Conoco,
Inc. designed to enhance both companies' coalbed methane programs.
Taurus will provide consulting and associated services relative to the
acquisition, exploration and development of coalbed methane properties
to complement Conoco's capabilities.
Substantially all of the gas produced from the coalbed methane wells
in which Taurus has an interest is being sold under long-term
contracts which provide markets for 100 percent of the wells'
production capacity and is sold at prices indexed to the monthly Gulf
Coast spot market. Contracts representing approximately one-third of
this gas are subject to price renegotiation during 1995.
ENVIRONMENTAL MATTERS: Taurus is subject to various environmental
regulations. Management believes that Taurus is in compliance with
currently applicable standards of the environmental agencies to which
it is subject and that potential environmental liabilities, if any,
are minimal. Also, to the extent Taurus has operating agreements with
various joint venture partners, environmental costs, if any, would be
shared proportionately.
- - PROPANE SALES
Prior to June 1994, Energen had been involved in the retail propane
distribution business through its subsidiary, W & J Propane Gas, Inc.
(W & J). In June 1994, W & J sold substantially all of its assets.
- - INTRASTATE GAS GATHERING AND TRANSMISSION
Energen operates an intrastate gas pipeline and gathering system
through its subsidiary, Basin Pipeline Corp. (Basin). Basin's
pipeline and gathering facilities primarily serve certain of Taurus's
coalbed methane properties.
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- - COMBUSTION TECHNOLOGY
Prior to May 1994, through its American Heat Tech, Inc. (Heat Tech)
subsidiary, Energen owned a 41 percent equity interest in American
Combustion, Inc. During May 1994, a substantial portion of this
interest was sold leaving Heat Tech with approximately an 8 percent
ownership interest. ACI designs, manufactures and markets high
temperature combustion technology products.
EMPLOYEES
The Company has 1,488 employees; Alagasco employs 1,318; Taurus employs 158;
and Energen's other subsidiaries employ 12.
ITEM 2. PROPERTIES
The corporate headquarters of Energen, Alagasco and Taurus are located in
leased office space in Birmingham, Alabama.
The properties of Alagasco consist primarily of its gas distribution system,
which includes more than 8,500 miles of main, more than 9,300 miles of service
lines, odorization and regulation facilities, and customer meters. Alagasco
also has two liquefied natural gas facilities, 23 commercial offices, nine
service centers, and other related property and equipment, some of which are
leased by Alagasco. Substantially all of Alagasco's fixed assets are subject to
the lien of its first mortgage bonds. The Montgomery, Alabama service center
also serves as collateral for a mortgage note, the terms of which are discussed
in Note 2 to the Consolidated Financial Statements which is incorporated by
reference from the 1994 Annual Report to Stockholders and is included in Part
IV, Item 14, Exhibit 13, herein.
For a description of Taurus's oil and gas properties, see the discussion under
Item 1--Business. Information concerning Taurus's production, reserves and
development is included in Note 15 to the Consolidated Financial Statements
which is incorporated by reference from the 1994 Annual Report to Stockholders
and is included in Part IV, Item 14, Exhibit 13, herein. The proved reserve
estimates are consistent with comparable reserve estimates filed by Taurus with
any federal authority or agency.
ITEM 3. LEGAL PROCEEDINGS
There are no material legal proceedings pending, other than routine litigation
incidental to the Company's business, in which the Company or any of its
subsidiaries is a party. There are no material legal proceedings to which any
officer or director of the Company or any of its subsidiaries is a party or has
a material interest adverse to the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth
quarter of 1994.
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EXECUTIVE OFFICERS OF THE REGISTRANTS
ENERGEN CORPORATION
Name Age Position (1)
---- --- ------------
Rex J. Lysinger 57 Chairman of the Board and Chief
Executive Officer (2)
Wm. Michael Warren, Jr. 47 President and Chief Operating Officer (3)
Geoffrey C. Ketcham 43 Executive Vice President, Chief
Financial Officer and Treasurer (4)
Dudley C. Reynolds 41 General Counsel and Secretary (5)
Gary C. Youngblood 51 Executive Vice President of Alagasco (6)
John A. Wallace 50 Senior Vice President--Methane of
Taurus (7)
James T. McManus 36 Vice President--Finance and Corporate
Development (8)
NOTES: (1) All executive officers of Energen have been employed by
Energen for the past five years. Officers serve at the
pleasure of its Board of Directors.
(2) Served as Vice President of Alagasco from July 1975 to January
1977, when he was elected President. Elected President of
Energen upon its formation in 1978. Elected Chairman of the
Board of Energen and its subsidiaries September 1982.
Currently Chairman of the Board and Chief Executive Officer of
Energen and its subsidiaries. Serves as a Director of Energen
and each of its subsidiaries.
(3) Served as Senior Vice President and General Counsel of
Alagasco from September 1983 to October 1984, when he was
elected President and Chief Operating Officer of that
corporation. Elected Executive Vice President of Energen June
1987 and elected President and Chief Operating Officer of
Energen April 1, 1991. Elected President and Chief Operating
Officer of all Energen subsidiaries (except W & J) January
1992. Serves as a Director of Energen and each of its
subsidiaries.
(4) Elected Controller of Alagasco November 1981, Vice President
and Controller June 1984, Vice President--Finance and Planning
of Alagasco June 1985 and Vice President--Planning of Energen
August 1986. Elected Vice President--Finance and Treasurer of
Energen and each of its subsidiaries June 1987. Elected
Senior Vice President--Finance and Treasurer of Energen and
each of its subsidiaries April 1989. Elected Executive Vice
President, Chief Financial Officer and Treasurer of Energen
and each of its subsidiaries April 1, 1991.
(5) Served as Staff Attorney for Energen and its subsidiaries to
November 1, 1984, when he was named Senior Attorney. Elected
Assistant Secretary in 1985 and Secretary effective September
1986. Elected Vice President--Legal and Secretary of Energen
and each of its subsidiaries June 1987. Elected General
Counsel and Secretary of Energen and each of its subsidiaries
April 1, 1991.
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(6) Served as District Manager--Birmingham District until June
1985, when he was elected Vice President--Birmingham
Operations; Elected Senior Vice President--Administration
April 1, 1991. Elected Executive Vice President October 1993.
(7) Served as Manager, Methane Development of Taurus until August
1988, when he was elected Vice President Methane Operations of
Taurus. Elected Vice President Methane Exploration and
Production of Taurus November 1990. Elected Senior Vice
President--Methane of Taurus February 1992.
(8) Served as Director of Corporate Accounting of Energen until
November 1988, when he was elected Controller of Energen;
Elected Controller of Alagasco May 1989. Elected Assistant
Vice President--Corporate Development of Energen June 1990.
Elected Vice President--Finance and Corporate Development of
Energen and Vice President--Finance and Planning of Alagasco
effective April 1, 1991.
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ALABAMA GAS CORPORATION
Name Age Position (1)
---- --- ------------
Rex J. Lysinger 57 Chairman of the Board and Chief
Executive Officer (2)
Wm. Michael Warren, Jr. 47 President and Chief Operating Officer (2)
Geoffrey C. Ketcham 43 Executive Vice President and Chief
Financial Officer (2)
Dudley C. Reynolds 41 General Counsel and Secretary (2)
Gary C. Youngblood 51 Executive Vice President (2)
Roy F. Etheredge 58 Senior Vice President--Operations (3)
T. Irving Hawkins 60 Senior Vice President--Marketing
Services (4)
James T. McManus 36 Vice President--Finance and Planning (2)
Gerald G. Turner 59 Vice President--Rates (5)
NOTES: (1) All executive officers of Alagasco have been employed by
Energen for the past five years. Officers serve at the
pleasure of the Board of Directors.
(2) See discussion of Energen officers above.
(3) Elected Assistant Vice President in 1983, Vice
President--Northern Division in 1984. Elected Vice
President--State Operations in 1985. Elected Senior Vice
President--Operations April 1, 1991.
(4) Served as General Manager--Marketing of Alagasco until August
1, 1982, when he was elected Vice President--Marketing
Services. Elected Senior Vice President--Marketing Services
April 1, 1991.
(5) Served as Director of Rates and Regulations until he was
elected Assistant Vice President--Rates in June 1987. Elected
Vice President--Rates May 1989.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
The information regarding Energen's common stock and the frequency and amount
of dividends paid during the past two years with respect to such stock is
incorporated by reference from the 1994 Annual Report to Stockholders, page 52,
and is included in Part IV, Item 14, Exhibit 13, herein. At October 29, 1994,
there were approximately 6,000 holders of record of Energen's common stock. For
restrictions on Energen's present and future ability to pay dividends, see Note
2 to the Consolidated Financial Statements which is incorporated by reference
from the 1994 Annual Report to Stockholders and is included in Part IV, Item
14, Exhibit 13, herein.
11
<PAGE> 13
At the date of this filing, Energen Corporation owns all the issued and
outstanding common stock of Alabama Gas Corporation.
ITEM 6. SELECTED FINANCIAL DATA
Energen Corporation
The information regarding selected financial data is incorporated by reference
from the 1994 Annual Report to Stockholders, pages 54-55, and is included in
Part IV, Item 14, Exhibit 13, herein.
Alabama Gas Corporation
(unaudited)
<TABLE>
<CAPTION>
==========================================================================================
YEARS ENDED SEPTEMBER 30, 1994 1993 1992 1991 1990
(IN THOUSANDS)
==========================================================================================
<S> <C> <C> <C> <C> <C>
Operating revenues $344,637 $330,560 $310,726 $309,128 $310,959
Net income $ 14,896 $ 13,024 $ 12,420 $ 11,970 $ 9,390
Cash dividends on common stock $ 8,695 $ 7,975 $ 7,630 $ 6,994 $ 4,301
Cash dividends on preferred stock $ -- $ 70 $ 85 $ 85 $ 97
- ------------------------------------------------------------------------------------------
Total assets $308,905 $264,548 $258,902 $246,573 $242,814
Long-term debt $ 84,391 $ 43,912 $ 60,979 $ 66,307 $ 69,865
Preferred stock $ -- $ -- $ 1,800 $ 1,800 $ 1,800
==========================================================================================
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
This information is incorporated by reference from the 1994 Annual Report to
Stockholders and is included in Part IV, Item 14, Exhibit 13, herein.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item for Energen Corporation and subsidiaries
is incorporated by reference from the 1994 Annual Report to Stockholders and is
included in Part IV, Item 14, Exhibit 13, herein. The information required by
this item for Alabama Gas Corporation is contained in Part IV, Item 14, herein.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding the executive officers of both Energen and Alagasco is
included in Part I. The other information required by Item 10 is incorporated
herein by reference from Energen's definitive proxy statement for the Annual
Meeting of Stockholders to be held January 25, 1995. The proxy statement will
be filed within 120 days after the end of the fiscal year covered by this Form
10-K. The directors and nominees for director
12
<PAGE> 14
of Alagasco are the same as those of Energen except the Alagasco directors do
not have staggered terms, thus the entire Alagasco Board has been nominated for
re-election to an annual term at the Annual Meeting.
ITEM 11. EXECUTIVE COMPENSATION
The information regarding executive compensation is incorporated herein by
reference from Energen's definitive proxy statement for the Annual Meeting of
Stockholders to be held January 25, 1995.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
A. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The information regarding the security ownership of the beneficial
owners of more than five percent of Energen's common stock is
incorporated herein by reference from Energen's definitive proxy
statement for the Annual Meeting of Stockholders to be held January
25, 1995.
B. SECURITY OWNERSHIP OF MANAGEMENT
The information regarding the security ownership of management is
incorporated herein by reference from Energen's definitive proxy
statement for the Annual Meeting of Stockholders to be held January
25, 1995.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information regarding certain relationships and related transactions is
incorporated herein by reference from Energen's definitive proxy statement for
the Annual Meeting of Stockholders to be held January 25, 1995.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
A. DOCUMENTS FILED AS PART OF THIS REPORT
(1) FINANCIAL STATEMENTS The financial statements listed in the
accompanying Index to Financial Statements and Financial
Statement Schedules are filed as part of this report and are
included in Part IV, Item 14, Exhibit 13, herein.
(2) FINANCIAL STATEMENT SCHEDULES The financial statement
schedules listed in the accompanying Index to Financial
Statements and Financial Statement Schedules are filed as part
of this report.
(3) EXHIBITS The exhibits listed on the accompanying Index to
Exhibits are filed as part of this report.
B. REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the fourth quarter of 1994.
13
<PAGE> 15
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities and
Exchange Act of 1934, the Registrants have duly caused this report to be signed
on their behalf by the undersigned thereunto duly authorized.
ENERGEN CORPORATION
(Registrant)
ALABAMA GAS CORPORATION
(Registrant)
December 21, 1994 /s/Rex J. Lysinger
- ----------------------- ------------------------------
DATE Rex J. Lysinger
Chairman of the Board, Chief
Executive Officer and Director
14
<PAGE> 16
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed by the following persons on behalf of the Registrants
and in the capacities and on the dates indicated:
December 21, 1994 /s/Rex J. Lysinger
- ----------------------- --------------------------------
DATE Rex J. Lysinger
Chairman of the Board, Chief
Executive Officer and Director
December 21, 1994 /s/Wm. Michael Warren, Jr.
- ----------------------- --------------------------------
DATE Wm. Michael Warren, Jr.
President, Chief Operating
Officer and Director
December 21, 1994 /s/Geoffrey C. Ketcham
- ----------------------- --------------------------------
DATE Geoffrey C. Ketcham
Executive Vice President, Chief
Financial Officer and Treasurer
December 21, 1994 /s/James T. McManus
- ----------------------- --------------------------------
DATE James T. McManus
Vice President--Finance and
Corporate Development of Energen
and Vice President--Finance and
Planning of Alagasco
December 21, 1994 /s/Dr. Stephen D. Ban
- ----------------------- --------------------------------
DATE Dr. Stephen D. Ban
Director
December 21, 1994 /s/James S. M. French
- ----------------------- --------------------------------
DATE James S. M. French
Director
December 21, 1994 /s/Harris Saunders, Jr.
- ----------------------- --------------------------------
DATE Harris Saunders, Jr.
Director
December 21, 1994 /s/Dr. Judy M. Merritt
- ----------------------- --------------------------------
DATE Dr. Judy M. Merritt
Director
15
<PAGE> 17
ENERGEN CORPORATION
ALABAMA GAS CORPORATION
INDEX TO FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
ITEM 14(A)
<TABLE>
<CAPTION>
1. Energen Corporation Reference Page
------------------- ----------------
1994
1994 Annual
10-K Report
-- - ------
<S> <C> <C> <C>
A. Financial Statements
Report of Independent Certified Public Accountants . . . . . . . . . . 53
Consolidated statements of income for the years ended
September 30, 1994, 1993 and 1992 . . . . . . . . . . . . . . . . . . 33
Consolidated balance sheets as of September 30,
1994 and 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Consolidated statements of shareholders' equity for the year
ended September 30, 1994, 1993 and 1992 . . . . . . . . . . . . . . . 36
Consolidated statements of cash flows for the years ended
September 30, 1994, 1993 and 1992 . . . . . . . . . . . . . . . . . . 37
Notes to consolidated financial statements . . . . . . . . . . . . . . 38
B. Financial Statement Schedules
Report of Independent Certified Public Accountants . . . . . . . . . . 39
Schedule V Property, Plant and Equipment . . . . . . . . . . . . . 40
Schedule VI Accumulated Depreciation, Depletion and
Amortization of Property, Plant and
Equipment . . . . . . . . . . . . . . . . . . . . . . . 43
Schedule VIII Valuation and Qualifying Accounts . . . . . . . . . . . 44
Schedule X Supplementary Income Statement Information . . . . . . 45
</TABLE>
16
<PAGE> 18
<TABLE>
<CAPTION>
Reference Page
------------------
1994
1994 Annual
10-K Report
-- - ------
<S> <C> <C>
2. Alabama Gas Corporation
-----------------------
A. Financial Statements
Report of Independent Certified Public Accounts . . . . . . . . . . . 22
Statements of income for the years ended
September 30, 1994, 1993 and 1992 . . . . . . . . . . . . . . . . . . 23
Balance sheets as of September 30, 1994 and 1993 . . . . . . . . . . . 24
Statements of retained earnings for the years ended
September 30, 1994, 1993 and 1992 . . . . . . . . . . . . . . . . . . 26
Statements of cash flows for the years ended
September 30, 1994, 1993 and 1992 . . . . . . . . . . . . . . . . . . 27
Notes to financial statements . . . . . . . . . . . . . . . . . . . . 28
B. Financial Statement Schedules
Schedule V Property, Plant and Equipment . . . . . . . . . . . . . 46
Schedule VI Accumulated Depreciation, Depletion and
Amortization of Property, Plant and
Equipment . . . . . . . . . . . . . . . . . . . . . . . 49
Schedule VIII Valuation and Qualifying Accounts . . . . . . . . . . . 50
Schedule X Supplementary Income Statement Information . . . . . . 51
</TABLE>
Schedules other than those listed above are omitted for the reason that they
are not required or are not applicable, or the required information is shown in
the financial statements or notes thereto.
17
<PAGE> 19
ENERGEN CORPORATION
ALABAMA GAS CORPORATION
INDEX TO EXHIBITS
ITEM 14(A)(3)
Exhibit
Number Description
- ------- -----------
*3(a) Restated Certificate of Incorporation of Energen Corporation (formerly
Alagasco, Inc.) which was filed as Exhibit 4(a) to Energen's
Registration Statement on Form S-8 (Registration No. 33-14855).
*3(b) Amendment to the Restated Certificate of Incorporation of Energen
Corporation (formerly Alagasco, Inc.) adopted on July 18, 1985, which
was filed as Exhibit 4(b) to Energen's Registration Statement on Form
S-8 (Registration No. 33-14855).
*3(c) Amendment to the Restated Certificate of Incorporation of Energen
Corporation adopted on January 15, 1987, which was filed as Exhibit
4(c) to Energen's Registration Statement on Form S-8 (Registration No.
33-14855).
*3(d) Amendment to the Restated Certificate of Incorporation of Energen
Corporation adopted on January 25, 1989, which was filed as Exhibit
4(d) to Energen's Registration Statement on Form S-3 (Registration No.
33-70464).
*3(e) Composite Restated Certificate of Incorporation of Energen
Corporation, as amended through February 12, 1989, which was filed as
Exhibit 4(e) to Energen's Registration Statement on Form S-3
(Registration No. 33-70464).
*3(f) Certificate of Adoption of Resolutions designating Series A Junior
Participating Preferred Stock (June 27, 1988) which was filed as
Exhibit 4(e) to Energen's Registration Statement on Form S-2
(Registration No. 33-25435).
*3(g) Bylaws of Energen Corporation, which were filed as Exhibit 4(e) to
Energen's Registration Statement on Form S-8 (Registration No.
33-14855).
*3(h) Joint Agreement of Merger, under the name Alabama Gas Corporation
(November 19, 1948), which was filed as Exhibit 4(a) to Alabama Gas'
Registration Statement on Form S-3 (Registration No. 33-12841).
*3(i) Alabama Gas Corporation, Certificate of Amendment to Joint Agreement
of Merger which constitutes the Certificate of Incorporation of said
Corporation (March 13, 1953), which was filed as Exhibit 4(b) to
Alabama Gas' Registration Statement on Form S-3 (Registration No.
33-12841).
*3(j) Alabama Gas Corporation, Certificate of Amendment to the Certificate
of Incorporation (April 22, 1954), which was filed as Exhibit 4(c) to
Alabama Gas' Registration Statement on Form S-3 (Registration No.
33-12841).
*3(k) Alabama Gas Corporation, Certificate of Amendment to the Joint
Agreement of Merger, as heretofore amended, which constitutes the
Certificate of Incorporation of Alabama Gas Corporation (January 20,
1959), which was filed as Exhibit 4(d) to Alabama Gas' Registration
Statement on Form S-3 (Registration No. 33-12841).
18
<PAGE> 20
*3(l) Alabama Gas Corporation, Certificate of Amendment to the Joint
Agreement of Merger, as heretofore amended, which constitutes the
Certificate of Incorporation of Alabama Gas Corporation (January 26,
1968), which was filed as Exhibit 4(e) to Alabama Gas' Registration
Statement on Form S-3 (Registration No. 33-12841).
*3(m) Alabama Gas Corporation, Certificate of Amendment to the Joint
Agreement of Merger, as heretofore amended, which constitutes the
Certificate of Incorporation of Alabama Gas Corporation (October 16,
1980), which was filed as Exhibit 4(f) to Alabama Gas' Registration
Statement on Form S-3 (Registration No. 33-12841).
*3(n) Articles of Amendment to the Certificate of Incorporation of Alabama
Gas Corporation (October 26, 1984), which was filed as Exhibit 4(g) to
Alabama Gas' Registration Statement on Form S-3 (Registration No.
33-12841).
*3(o) Articles of Amendment to the Certificate of Incorporation of Alabama
Gas Corporation (December 18, 1986), which was filed as Exhibit 4(h)
to Alabama Gas' Registration Statement on Form S-3 (Registration No.
33-12841).
*3(p) Composite Joint Agreement of Merger under the name Alabama Gas
Corporation, as Amended March 20, 1986, which was filed as Exhibit
4(i) to Alabama Gas' Registration Statement on Form S-3 (Registration
No. 33-12841).
*3(q) Alabama Gas Corporation, Certificate filed pursuant to Section 33 of
Act Number 414 of the Regular Session of the Legislature of the State
of Alabama (August 26, 1965, reclassifying and authorizing $4.70
Series Cumulative Preferred Stock), which was filed as Exhibit 4(j) to
Alabama Gas' Registration Statement on Form S-3 (Registration No.
33-12841).
*3(r) By-Laws of Alabama Gas Corporation, which was filed as Exhibit 4(k) to
Alabama Gas' Registration Statement on Form S-3 (Registration No.
33-12841).
*4(a) Rights Agreement, dated as of July 27, 1988, between Energen
Corporation and AmSouth Bank, N.A., Rights Agent, which was filed as
Exhibit 1 to Energen's Registration Statement on Form 8-A (File No.
1-7810).
*4(b) Amendment of Rights Agreement, dated as of February 28, 1990, between
Energen Corporation and AmSouth Bank, N.A., Rights Agent, which was
filed as Exhibit 2 to Energen's Form 8 Amendment No. 2 to its
Registration Statement on Form 8-A (File No. 1-7810).
*4(c) Indenture, dated as of January 1, 1992, between Energen Corporation
and Boatmen's Trust Company, Trustee, which was filed as Exhibit 4 to
Energen's Amendment No. 1 to Registration Statement on Form S-3
(Registration No. 33-44936).
*4(d) Indenture, dated as of March 1, 1993, between Energen Corporation and
Boatmen's Trust Company, Trustee, which was filed as Exhibit 4 to
Energen's to Registration Statement on Form S-3 (Registration No.
33-25435).
*4(e) Ninth Supplemental Indenture, dated as of April 1, 1949, between
Alabama Gas Corporation and Chemical Bank and Trust Company, Trustee,
supplementing, amending, and restating the First Mortgage and Deed of
Trust between Birmingham Gas Company and Chemical Bank and Trust
Company, Trustee, dated April 1, 1941 (filed as Exhibit 7(a)(J) to
Alabama Gas' Form S-1, Registration Statement 2-7910, effective March
26, 1949).
19
<PAGE> 21
*4(f) Nineteenth Supplemental Indenture dated as of December 1, 1985,
between Alabama Gas Corporation and Chemical Bank and Trust Company,
Trustee, which was filed as Exhibit 4(o) to Energen's Registration
Statement on Form S-3 (Registration No. 33-70464).
*4(g) Indenture dated as of October 1, 1989, between Alabama Gas Corporation
and Boatmen's Trust Company, Trustee, which was filed as Exhibit 4(l)
to Alabama Gas' Amendment No. 1 to Registration Statement on Form S-3
(Registration No. 33-31400).
*4(h) Indenture dated as of November 1, 1993, between Alabama Gas
Corporation and NationsBank of Georgia, National Association,
Trustee, which was filed as Exhibit 4(k) to Alabama Gas's Registration
Statement on Form S-3 (Registration No. 33-70466).
*10(a) Form of Service Agreement Under Rate Schedule CSS (No. S10710),
between Southern Natural Gas Company and Alabama Gas Corporation as
filed as Exhibit 10(a) to Energen's Annual Report on Form 10-K for the
year ended September 30, 1993.
*10(b) Form of Service Agreement Under Rate Schedule IT (No. 790420), between
Southern Natural Gas Company and Alabama Gas Corporation as filed as
Exhibit 10(b) to Energen's Annual Report on Form 10-K for the year
ended September 30, 1993.
*10(c) Form of Service Agreement Under Rate Schedule FT-NN (No. 866941),
between Southern Natural Gas Company and Alabama Gas Corporation as
filed as Exhibit 10(c) to Energen's Annual Report on Form 10-K for the
year ended September 30, 1993.
*10(d) Form of Service Agreement Under Rate Schedule FT (No. 866940) between
Southern Natural Gas Company and Alabama Gas Corporation as filed as
Exhibit 10(d) to Energen's Annual Report on Form 10-K for the year
ended September 30, 1993.
*10(e) Form of Executive Retirement Supplement Agreement between Energen
Corporation and certain executive officers as filed as Exhibit 10(f)
to Energen's Annual Report on Form 10-K for the year ended September
30, 1993.
10(f) Amendment to Executive Retirement Supplement Agreement effective as of
June 22, 1994, between Energen Corporation and certain executive
officers.
*10(g) Restricted Stock Incentive Plan of Energen Corporation, which was
filed as Exhibit 4 to Post Effective Amendment No. 2 to Energen
Corporation's Registration Statement on Forms S-8 and S-3
(Registration No. 2-89855).
*10(h) Severance Compensation Agreement between Energen Corporation and
certain executive officers, which was filed as Exhibit 10(e) to
Energen's Annual Report on Form 10-K for the year ended September 30,
1992.
*10(i) Energen Corporation 1988 Stock Option Plan as filed as Exhibit 10(i)
to Energen's Annual Report on Form 10-K for the year ended September
30, 1993.
*10(j) Energen Corporation 1992 Long-Range Performance Share Plan, dated as
of October 1, 1991, which was filed as Exhibit A to the Registrant's
Proxy Statement for its January 22, 1992 Annual Meeting (File No.
1-7810).
20
<PAGE> 22
*10(k) Energen Corporation 1992 Directors Stock Plan, effective as of January
22, 1992, which was filed as Exhibit B to Energen's Proxy Statement
for its January 22, 1992 Annual Meeting (File No. 1-7810).
*10(l) Energen Corporation Director Fees Deferral Plan as filed as Exhibit
10(l) to Energen's Annual Report on Form 10-K for the year ended
September 30, 1993.
10(m) Energen Corporation Annual Incentive Compensation Plan, Revised 5/90,
as amended effective October 1, 1993.
13 Information incorporated by reference from the Energen Corporation
1994 Annual Report to Stockholders
21 Subsidiaries of Energen Corporation
23(a) Consent of Independent Certified Public Accountants (Energen).
23(b) Consent of Independent Certified Public Accountants (Alagasco).
27.1 Financial Data Schedule of Alabama Gas Corporation (for SEC purposes
only)
27.2 Financial Data Schedule of Energen Corporation (for SEC purposes only)
*Incorporated by reference
21
<PAGE> 23
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS OF ALABAMA GAS CORPORATION:
We have audited the financial statements and the financial statement schedules
of Alabama Gas Corporation listed in the index on pages 16 and 17 of this Form
10-K. These financial statements and financial statement schedules are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Alabama Gas Corporation as of
September 30, 1994 and 1993, and the results of its operations and its cash
flows for each of the three years in the period ended September 30, 1994, in
conformity with generally accepted accounting principles. In addition, in our
opinion, the financial statement schedules referred to above, when considered
in relation to the basic financial statements taken as a whole, present fairly,
in all material respects, the information required to be included therein.
As discussed in Note 12 to the financial statements, the Company changed its
method of accounting for certain other postretirement benefits, effective
October 1, 1993, and income taxes effective October 1, 1991.
Coopers & Lybrand L.L.P.
Birmingham, Alabama
October 26, 1994
22
<PAGE> 24
STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
<TABLE>
<CAPTION>
===============================================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1994 1993 1992
===============================================================================================
<S> <C> <C> <C>
OPERATING REVENUES $344,637 $330,560 $310,726
- -----------------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas 188,592 187,800 176,411
Operations 72,639 66,196 61,470
Maintenance 9,147 8,781 8,611
Depreciation 17,941 17,206 17,154
Income taxes
Current 10,623 5,407 4,777
Deferred, net (2,418) 1,530 1,945
Deferred investment tax credits, net (487) (528) (535)
Taxes, other than income taxes 26,301 24,196 21,165
- -----------------------------------------------------------------------------------------------
Total operating expenses 322,338 310,588 290,998
- -----------------------------------------------------------------------------------------------
OPERATING INCOME 22,299 19,972 19,728
- -----------------------------------------------------------------------------------------------
OTHER INCOME
Allowance for funds used during construction 465 163 50
Other, net 452 376 238
- -----------------------------------------------------------------------------------------------
Total other income 917 539 288
- -----------------------------------------------------------------------------------------------
INTEREST CHARGES
Interest on long-term debt 6,475 5,532 6,243
Other interest expense 1,845 1,955 1,353
- -----------------------------------------------------------------------------------------------
Total interest charges 8,320 7,487 7,596
- -----------------------------------------------------------------------------------------------
NET INCOME 14,896 13,024 12,420
Less cash dividends on cumulative preferred stock -- 70 85
- -----------------------------------------------------------------------------------------------
NET INCOME AVAILABLE FOR COMMON $ 14,896 $ 12,954 $ 12,335
===============================================================================================
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
23
<PAGE> 25
BALANCE SHEETS
ALABAMA GAS CORPORATION
=============================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1994 1993
=============================================================================
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Utility plant $464,593 $429,115
Less accumulated depreciation 231,327 215,892
- -----------------------------------------------------------------------------
Utility plant, net 233,266 213,223
- -----------------------------------------------------------------------------
Other property, net 183 83
- -----------------------------------------------------------------------------
CURRENT ASSETS
Cash 156 480
Accounts receivable
Gas 22,209 23,563
Merchandise 1,326 1,256
Other 1,512 1,011
Allowance for doubtful accounts (2,000) (1,800)
Inventories, at average cost
Storage gas inventory 24,363 --
Materials and supplies 5,688 5,851
Liquified natural gas in storage 3,349 3,636
Deferred gas costs 1,460 2,966
Deferred income taxes 5,724 2,587
Prepayments and other 2,595 2,520
=============================================================================
Total current assets 66,382 42,070
- -----------------------------------------------------------------------------
DEFERRED CHARGES AND OTHER ASSETS 9,074 9,172
- -----------------------------------------------------------------------------
TOTAL ASSETS $308,905 $264,548
=============================================================================
The accompanying Notes to Financial Statements are an integral part of these
statements.
24
<PAGE> 26
BALANCE SHEETS
ALABAMA GAS CORPORATION
<TABLE>
<CAPTION>
================================================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1994 1993
================================================================================================
<S> <C> <C>
CAPITAL AND LIABILITIES
CAPITALIZATION
Common shareholder's equity
Common stock, $0.01 par value; 3,000,000 shares authorized,
1,972,052 shares outstanding in 1994 and 1993 $ 20 $ 20
Premium on capital stock 31,682 21,682
Capital Surplus 2,802 2,802
Retained Earnings 81,087 74,886
- ------------------------------------------------------------------------------------------------
Total common shareholder's equity 115,591 99,390
Cumulative preferred stock, $0.01 par value, 120,000 shares
authorized -- --
Long-term debt 84,391 43,912
- ------------------------------------------------------------------------------------------------
Total capitalization 199,982 143,302
- ------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Long-term debt due within one year 2,823 3,193
Notes payable to banks 4,000 29,000
Accounts payable
Other 19,002 18,772
Affiliated companies 132 1,252
Accrued taxes 14,241 8,960
Customers' deposits 17,462 16,717
Supplier refunds due customers 832 740
Other amounts due customers 10,902 4,365
Accrued wages and benefits 5,659 5,261
Other 7,605 4,821
- ------------------------------------------------------------------------------------------------
Total current liabilities 82,658 93,081
- ------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes 13,704 12,416
Accumulated deferred investment tax credits 4,590 5,077
Regulatory liability 6,960 7,717
Customer advances for construction and other 1,011 751
Other -- 2,204
- ------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 26,265 28,165
- ------------------------------------------------------------------------------------------------
TOTAL CAPITAL AND LIABILITIES $308,905 $264,548
================================================================================================
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
25
<PAGE> 27
STATEMENTS OF RETAINED EARNINGS
ALABAMA GAS CORPORATION
<TABLE>
<CAPTION>
========================================================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1994 1993 1992
========================================================================================================
<S> <C> <C> <C>
RETAINED EARNINGS AT BEGINNING OF YEAR $74,886 $69,907 $65,202
Add net income 14,896 13,024 12,420
Less cash dividends on common stock 8,695 7,975 7,630
Less cash dividends on preferred stock -- 70 85
- --------------------------------------------------------------------------------------------------------
RETAINED EARNINGS AT END OF YEAR $81,087 $74,886 $69,907
========================================================================================================
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
26
<PAGE> 28
STATEMENTS OF CASH FLOW
ALABAMA GAS CORPORATION
<TABLE>
<CAPTION>
========================================================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1994 1993 1992
========================================================================================================
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net Income $ 14,896 $ 13,024 $ 12,420
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 17,941 17,206 17,154
Deferred income taxes, net (2,418) 1,530 1,945
Deferred investment tax credits (487) (528) (535)
Net change in:
Accounts receivable 896 (3,787) (1,888)
Inventories (23,913) (94) (306)
Accounts payable (890) 3,398 2,017
Other current assets and liabilities 17,268 968 (6,828)
Other, net (2,116) (1,536) (2,986)
- --------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 21,177 30,181 20,993
- --------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to property, plant and equipment (37,853) (21,743) (20,003)
Net advances (to) from holding company 87 (87) --
Other, net 181 (320) 522
- --------------------------------------------------------------------------------------------------------
Net cash used in investing activities (37,585) (22,150) (19,481)
- --------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Payment of dividends on common stock (8,695) (7,975) (7,630)
Payment of dividends on preferred stock -- (70) (85)
Reduction of long-term debt and preferred stock (9,891) (19,500) (4,822)
Proceeds from medium term notes 49,670 -- --
Proceeds from capital contribution 10,000 -- --
Net advances (to) from holding company -- (6,299) 6,050
Net change in short-term debt (25,000) 24,000 5,000
Other, net -- (101) --
- --------------------------------------------------------------------------------------------------------
Net cash used in (provided by) financing activities 16,084 (9,945) 1,487
- --------------------------------------------------------------------------------------------------------
Net change in cash (324) (1,914) 25
Cash at beginning of period 480 2,394 2,369
- --------------------------------------------------------------------------------------------------------
Cash at end of period $ 156 $ 480 $ 2,394
========================================================================================================
</TABLE>
The accompanying Notes to Financial Statements are an integral part of these
statements.
27
<PAGE> 29
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Alabama Gas Corporation (Alagasco), a wholly-owned subsidiary of Energen
Corporation, is the largest natural gas distribution utility in the State of
Alabama, serving customers primarily in central and north Alabama. The
following is a description of its significant accounting policies and
practices.
A. UTILITY PLANT AND DEPRECIATION
Utility plant is stated at original cost which includes an allowance for funds
used during construction. Maintenance is charged for the cost of normal
repairs and the renewal or replacement of an item of property which is less
than a retirement unit. When property which represents a retirement unit is
replaced or removed, the cost of such property is credited to utility plant
and, together with the cost of removal less salvage, is charged to the
accumulated reserve for depreciation.
Depreciation is provided on the straight-line method over the estimated useful
lives of utility property at rates established by the Alabama Public Service
Commission (APSC). Approved depreciation rates averaged approximately 4.3
percent in 1994 and 1993 and 4.4 percent in 1992.
B. OPERATING REVENUE AND GAS COSTS
In accordance with industry practice, Alagasco records revenue on a monthly and
cycle billing basis. The Company extends credit to its residential and
industrial utility customers which are located primarily in central and north
Alabama. The commodity cost of purchased gas applicable to gas delivered to
customers but not yet billed under the cycle billing method is deferred as a
current asset.
C. INCOME TAXES
Alagasco files a consolidated income tax return with its parent. The
consolidated income taxes are allocated to the appropriate subsidiaries using
the separate return method. Deferred income taxes reflect the impact of
temporary differences between the tax basis of assets and liabilities and their
carrying amounts for financial reporting purposes, and are measured in
compliance with enacted tax laws. Investment tax credits have been deferred
and are being amortized over the lives of the related assets.
D. CASH EQUIVALENTS
Alagasco includes highly liquid marketable securities and debt instruments
purchased with an original maturity of three months or less in cash
equivalents.
28
<PAGE> 30
2. LONG-TERM DEBT AND NOTES PAYABLE
Long-term debt consists of the following:
<TABLE>
<CAPTION>
==============================================================================================
AS OF SEPTEMBER 30, (IN THOUSANDS) 1994 1993
==============================================================================================
<S> <C> <C>
First Mortgage Bonds, 11% Series H, due $1,500,000 annually
to January 15, 1999 $ 7,500 $ 9,000
Medium term notes, interest ranging from 5.4% to 7.2%, for notes
redeemable December 1, 1998 to December 15, 2023 50,000 --
9% debentures, due up to $1,200,000 annually to November 1, 2014 28,758 28,758
8.75% debentures, redeemed during fiscal year 1994 -- 8,299
Mortgage note payable, due $30,800 quarterly to April 1, 2002;
interest is variable 956 1,048
- ----------------------------------------------------------------------------------------------
Total 87,214 47,105
Less amounts due within one year 2,823 3,193
- ----------------------------------------------------------------------------------------------
Total $84,391 $43,912
==============================================================================================
</TABLE>
Substantially all utility plant serves as collateral for the First Mortgage
Bonds. In addition, utility plant having a net book value of $1,703,000 serves
as collateral for the mortgage note payable which has a variable interest rate
of 1.47 percent above the 91-day U.S. Treasury Bill rate, adjusted quarterly.
The applicable year-end interest rate was 5.66 percent and 4.54 percent for
1994 and 1993, respectively.
The aggregate maturities of long-term debt for the next five years are as
follows:
===============================================================================
YEARS ENDING SEPTEMBER 30, (IN THOUSANDS)
===============================================================================
1995 1996 1997 1998 1999
- -------------------------------------------------------------------------------
$2,823 $2,823 $2,823 $2,823 $8,173
===============================================================================
Alagasco is subject to various restrictions on the payment of dividends. The
most restrictive provision is, under the 9 percent debentures, utility
dividends or other distributions with respect to utility common stock may not
be made unless the utility maintains a consolidated tangible net worth, as
defined, of at least $50 million. At September 30, 1994, Alagasco had a
tangible net worth of $115,364,000.
Energen and Alagasco have short-term credit lines and other credit facilities
of $110 million available to either entity for working capital needs. The
following is a summary of information relating to notes payable to banks:
29
<PAGE> 31
<TABLE>
<CAPTION>
======================================================================================
AS OF SEPTEMBER 30, (IN THOUSANDS) 1994 1993 1992
======================================================================================
<S> <C> <C> <C>
Amount outstanding $ 4,000 $ 29,000 $ 5,000
Other Energen outstanding 2,000 11,000 --
Available for borrowings 104,000 70,000 70,000
- --------------------------------------------------------------------------------------
Total $110,000 $110,000 $75,000
======================================================================================
Maximum amount outstanding at any month-end $ 60,000 $ 29,000 $25,000
Average daily amount outstanding $ 13,460 $ 23,071 $ 9,087
Weighted average interest rates based on:
Average daily amount outstanding 3.32% 3.41% 4.62%
Amount outstanding at year-end 5.17% 3.35% 3.63%
=======================================================================================
</TABLE>
Total interest expense in 1994, 1993 and 1992 was $8,320,000, $7,487,000, and
$7,596,000, respectively.
3. REGULATORY
As an Alabama utility, Alagasco is subject to regulation by the APSC which, in
1983, established the Rate Stabilization and Equalization (RSE) rate-setting
process. RSE was extended for the third time on December 3, 1990, for a
three-year period. Under the terms of that extension, RSE shall continue
after November 30, 1993, unless, after notice to the Company, the Commission
votes to either modify or discontinue its operation. On October 4, 1993, the
Commission unanimously voted to extend RSE until such time as certain hearings
mandated by the Energy Policy Act of 1992 (Energy Act) in connection with
integrated resource planning and demand side management programs are completed.
The Energy Act proceedings are expected to conclude during fiscal 1995 at which
time it is expected that the Commission will begin reviewing Alagasco's RSE.
No time table for review has yet been established.
Under RSE as extended, the APSC conducts quarterly reviews to determine, based
on Alagasco's projections and fiscal year-to-date performance, whether
Alagasco's return on equity for the fiscal year will be within the allowed
range of 13.15 percent to 13.65 percent. Reductions in rates can be made
quarterly to bring the projected return within the allowed range; increases,
however, are allowed only once each fiscal year, effective December 1, and
cannot exceed 4 percent of prior-year revenues. RSE limits the utility's
equity upon which a return is permitted to 60 percent of total capitalization
and provides for certain cost control measures designed to monitor the
Company's operations and maintenance (O&M) expense. If O&M expense per
customer falls within 1.25 percentage points above or below the Consumer Price
Index For All Urban Customers (index range), no adjustment is required. If,
however, O&M expense per customer exceeds the index range, three-quarters of
the difference will be returned to the customers. To the extent O&M expense
per customer is less than the index range, the utility will benefit by one-half
of the difference through future rate adjustments. Effective December 15,
1990, the APSC approved a temperature adjustment to customers' monthly bills to
mitigate the effect of departures from normal temperature on Alagasco's
earnings. The calculation is performed monthly, and the adjustment to
customer's bills is made in the same month the weather variation occurs.
The Company's rate schedules for natural gas distribution charges contained a
Purchased Gas Adjustment (PGA) rider in 1993 which permitted the pass-through
of changes in gas costs to customers. The APSC approved, effective October 4,
1993, the replacement of the PGA rider with the new Gas Supply Adjustment rider
in order to accommodate changes in gas supply purchases resulting from
implementation of FERC Order 636, including gas supply realignment surcharges
imposed by the Company's suppliers.
30
<PAGE> 32
In accordance with APSC-directed regulatory accounting procedures, Alagasco in
1989 began returning excess utility deferred taxes which resulted from a
reduction in the federal statutory tax rate from 46 percent to 34 percent using
the average rate assumption method. This method provides for the return to
ratepayers of excess deferred taxes over the lives of the related assets. In
1993 those excess taxes were reduced as a result of a federal tax rate increase
from 34 percent to 35 percent. Approximately $3.1 million of remaining excess
utility deferred taxes is being returned to ratepayers over approximately 16
years.
4. CAPITAL STOCK
Alagasco's authorized common stock consists of 3 million, $0.01 par value
common shares. At September 30, 1994 and 1993, 1,972,052 shares were issued
and outstanding. Alagasco is authorized to issue 120,000 shares of preferred
stock, par value $0.01 per share, in one or more series. On July 30, 1993, all
outstanding shares of Alagasco's $4.70 Series cumulative preferred stock were
redeemed.
5. INCOME TAXES
The components of income taxes consist of the following:
<TABLE>
<CAPTION>
===================================================================================
FOR THE YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1994 1993 1992
===================================================================================
<S> <C> <C> <C>
Taxes estimated to be payable currently:
Federal $ 9,664 $4,911 $4,337
State 959 496 440
- -----------------------------------------------------------------------------------
Total current 10,623 5,407 4,777
- -----------------------------------------------------------------------------------
Taxes deferred:
Federal (2,689) 867 1,230
State (216) 135 180
- -----------------------------------------------------------------------------------
Total deferred (2,905) 1,002 1,410
- -----------------------------------------------------------------------------------
Total income tax expense $ 7,718 $6,409 $6,187
===================================================================================
</TABLE>
As discussed in Note 12, Alagasco adopted Statement of Financial Accounting
Standard (SFAS) No. 109 as of October 1, 1991.
Temporary differences which give rise to a significant portion of deferred tax
assets and liabilities for 1994 and 1993 are as follows:
31
<PAGE> 33
======================================================================
AS OF SEPTEMBER 30, 1994 (IN THOUSANDS) 1994 1993
======================================================================
Deferred tax assets:
Deferred investment tax credits $ 1,567 $ 1,748
Regulatory liabilities 2,585 2,866
Deferred revenue 403 516
Self-insurance reserve 1,339 842
Unbilled revenue 1,454 1,426
Allowance for uncollectible accounts 878 669
Accrued vacation 981 903
Gas supply realignment costs 1,123 --
Other, net 1,170 430
- ----------------------------------------------------------------------
Subtotal 11,500 9,400
Valuation allowance -- --
- ----------------------------------------------------------------------
Total deferred tax assets $11,500 $ 9,400
======================================================================
Deferred tax liabilities:
Depreciation and basis differences $17,704 $16,893
Pension and other benefit costs 1,457 1,181
Purchased gas adjustment -- 988
Other, net 319 167
- ----------------------------------------------------------------------
Total deferred tax liabilities $19,480 $19,229
======================================================================
No valuation allowance with respect to deferred taxes is deemed necessary, as
the Company anticipates generating adequate future taxable income to realize
the benefits of all deferred tax assets on the balance sheet.
Total income tax expense differs from the amount which would be provided by
applying the statutory federal income tax rate to pretax earnings as
illustrated below:
<TABLE>
<CAPTION>
==========================================================================================
FOR THE YEAR ENDED SEPTEMBER 30, (IN THOUSANDS) 1994 1993 1992
==========================================================================================
<S> <C> <C> <C>
Income tax expense at statutory federal income tax rate $7,915 $6,729 $6,298
Increase (decrease) resulting from:
Investment tax credits -- deferred (487) (528) (535)
Return of utility excess deferred taxes (76) (172) --
State income taxes, net of federal income tax benefit 486 412 408
Other, net (120) (32) 16
- ------------------------------------------------------------------------------------------
Total income tax expense $7,718 $6,409 $6,187
==========================================================================================
</TABLE>
There were no tax-related balances due from Alagasco to affiliates at September
30, 1994; the tax-related balance due to affiliates from Alagasco as of
September 30, 1993, was $1,239,000, and is included in the amounts payable to
affiliates in Note 13.
32
<PAGE> 34
6. RETIREMENT INCOME PLANS AND OTHER BENEFITS
All information presented concerning retirement income and other benefit plans
includes other affiliates of Energen Corporation as well as Alagasco.
Energen has two defined benefit non-contributory pension plans which cover
substantially all employees. Benefits are based on years of service and final
earnings. The Company's policy is to use the "projected unit credit" actuarial
method for funding and financial reporting purposes. The expense (income) for
the plan covering the majority of employees for the years ended September 30,
1994, 1993 and 1992 was $15,000, $(118,000), and $(278,000), respectively. The
expense for the second plan covering employees under labor union agreements for
1994, 1993 and 1992 was $555,000, $557,000 and $503,000, respectively.
The funded status of the plans is as follows:
<TABLE>
<CAPTION>
=====================================================================================================
ASSETS EXCEED ACCUMULATED BENEFITS
AS OF JUNE 30, (IN THOUSANDS) ACCUMULATED BENEFITS EXCEED ASSETS
=====================================================================================================
1994 1993 1994 1993
---- ---- ---- ----
<S> <C> <C> <C> <C>
Vested benefits $(48,354) $(46,513) $(12,860) $(12,258)
Nonvested benefits (5,530) (5,403) (2,253) (2,121)
- ----------------------------------------------------------------------------------------------------
Accumulated benefit obligation (53,884) (51,916) (15,113) (14,379)
Effects of salary progression (10,332) (9,803) -- --
- ----------------------------------------------------------------------------------------------------
Projected benefit obligation (64,216) (61,719) (15,113) (14,379)
Fair value of plan assets, primarily
equity and fixed income securities 72,004 73,576 11,863 11,815
Unrecognized net gain 2,646 (434) 1,034 124
Unrecognized prior service cost 46 51 1,554 1,696
Unrecognized net transition obligation (asset) (6,524) (7,332) 452 509
Additional minimum liability -- -- (3,040) (2,329)
- ----------------------------------------------------------------------------------------------------
Accrued pension asset (liability) $ 3,956 $ 4,142 $ (3,250) $ (2,564)
====================================================================================================
</TABLE>
At September 30, 1994 and 1993, the discount rate used to measure the projected
benefit obligation was 7.5 percent for both plans, and the annual rate of
salary increase for the salaried plan was 5.5 percent. The expected long-term
rate of return on plan assets was 8.25 percent for both plans in 1994 and 8
percent in 1993.
33
<PAGE> 35
The components of net pension costs for 1994, 1993 and 1992 were:
<TABLE>
<CAPTION>
============================================================================================
FOR THE YEARS ENDED SEPTEMBER 30, ASSETS EXCEED ACCUMULATED BENEFITS
(IN THOUSANDS) ACCUMULATED BENEFITS EXCEED ASSETS
============================================================================================
1994 1993 1992 1994 1993 1992
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 1,873 $ 1,678 $ 1,560 $ 224 $ 187 $ 176
Interest cost on projected
benefit obligation 4,550 4,097 3,807 1,042 1,018 970
Actual return on plan assets (504) (6,858) (6,123) (372) (1,048) (1,116)
Net amortization and deferral (5,904) 965 478 (339) 400 473
- --------------------------------------------------------------------------------------------
Net pension (income) expense $ 15 $ (118) $ (278) $ 555 $ 557 $ 503
============================================================================================
</TABLE>
Energen has deferred compensation plan agreements for certain key executives
providing for payments upon retirement, death or disability. The deferred
compensation expense under these agreements for 1994, 1993 and 1992 was
$461,000, $650,000, and $528,000, respectively.
In addition to providing pension benefits, Energen provides certain
post-retirement health care and life insurance benefits. Substantially all of
Energen's employees may become eligible for such benefits if they reach normal
retirement age while working for the Company. In a prior year, the company
adopted SFAS No. 106, Employers' Accounting for Postretirement Benefits Other
Than Pensions, with respect to the accrual of such costs for salaried
employees. During fiscal year 1994, the Company adopted SFAS 106 with respect
to such costs for employees under collective bargaining agreements. There is
no cumulative effect on the income statement resulting from the adoption of
SFAS 106 as the Company elected to amortize transition costs over a 20-year
period. On December 6, 1993, the APSC adopted Order 4-3454 which allows the
Company to recover all costs accrued under SFAS 106 through rates.
While the Company has not adopted a formal funding policy, all of its accrued
post-retirement liability was funded at year-end. The expense for salaried
employees for the years ended September 30, 1994, 1993 and 1992 was $2,319,000,
$2,677,000, and $2,439,000, respectively. Prior to 1994, the Company
recognized the cost of providing post-retirement benefits for union employees
on a "pay-as-you-go" basis. These benefits were provided through a
self-insurance arrangement and through insurance companies whose premiums were
based on the benefits paid during the year. In 1994 the expense for union
employees was $3,685,000, an increase of $2,246,000 over what would have been
recognized under the "pay-as-you-go" method. Expense of $982,000 and $882,000
was incurred during 1993 and 1992, respectively. The "projected unit credit"
actuarial method was used to determine the normal cost and actuarial liability.
A reconciliation of the estimated status of the obligation is as follows:
<TABLE>
<CAPTION>
===============================================================================================
AS OF JUNE 30, (IN THOUSANDS) SALARIED EMPLOYEES UNION EMPLOYEES
===============================================================================================
1994 1993 1994 1993
---- ---- ---- ----
<S> <C> <C> <C> <C>
Accumulated post-retirement benefit obligation $(21,296) $(23,067) $(24,564) $ --
Plan assets 9,408 6,488 1,248 --
Unamortized amounts 11,751 14,567 21,357 --
- -----------------------------------------------------------------------------------------------
Accrued post-retirement benefit liability $ (137) $ (2,123) $ (1,959) $ --
===============================================================================================
</TABLE>
34
<PAGE> 36
Net periodic post-retirement benefit cost for the years ended September 30,
1994, 1993 and 1992, included the following:
<TABLE>
<CAPTION>
========================================================================================================
FOR THE YEAR ENDED SEPTEMBER 30, (IN THOUSANDS) SALARIED EMPLOYEES UNION EMPLOYEES
========================================================================================================
1994 1993 1992 1994 1993 1992
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 450 $ 464 $ 321 $ 481 $ -- $ --
Interest cost on accumulated post-retirement
benefit obligation 1,726 1,457 1,276 1,920 -- --
Amortization of transition obligation 723 842 842 1,285 -- --
Amortization of actuarial gains and losses -- 49 -- -- -- --
Deferred asset (gain) loss (453) -- -- -- -- --
Actual return on plan assets (127) (135) -- (1) -- --
- --------------------------------------------------------------------------------------------------------
Net periodic post-retirement benefit expense $2,319 $2,677 $2,439 $3,685 $ -- $ --
========================================================================================================
</TABLE>
The weighted average health care cost trend rate used in determining the
accumulated post-retirement benefit obligation was 8 percent in 1994 and in
1993 and 8.5 percent in 1992. That assumption has a significant effect on the
amounts reported. For example, with respect to salaried employees, increasing
the weighted average health care cost trend rate by 1 percent would increase
the accumulated post-retirement benefit obligation by 3.8 percent and the net
periodic post-retirement benefit cost by 4.7 percent. For union employees
increasing the weighted average health care cost trend rate by 1 percent with
respect to union employees would increase the accumulated post-retirement
benefit obligation by 5.8 percent and the net periodic post-retirement benefit
cost by 5.4 percent. The weighted average discount rate used in determining the
accumulated post-retirement benefit obligation was 7.5 percent in 1994 and 1993
and 8 percent in 1992.
Energen has a long-term disability plan covering most salaried employees.
Expense for the years ended September 30, 1994, 1993 and 1992 was $150,000,
$129,000, and $129,000, respectively.
7. COMMITMENTS
Alagasco has various firm gas supply and firm gas transportation contracts,
which expire at various dates through the year 2008. These contracts typically
contain minimum demand charge obligations on the part of Alagasco.
In January 1989, Alagasco entered into an agreement with a financial
institution whereby it can sell on an ongoing basis, with recourse, certain
installment receivables related to its merchandising program up to a maximum of
$15 million. During 1994 and 1993, Alagasco sold $6,784,000 and $5,608,000,
respectively, of installment receivables. At September 30, 1994 and 1993, the
balance of these installment receivables was $13,027,000 and $11,699,000,
respectively. Receivables sold under this agreement are considered financial
instruments with off-balance-sheet risk. Alagasco's exposure to credit loss in
the event of non-performance by customers is represented by the balance of
installment receivables.
35
<PAGE> 37
8. LEASES
Total payments related to leases included as operating expense in the
accompanying statements of income amounted to $2,147,000, $2,332,000, and
$2,447,000 in 1994, 1993 and 1992, respectively. Minimum future rental
payments (in thousands) required after 1994 under leases with initial or
remaining noncancelable lease terms in excess of one year are as follows:
<TABLE>
<CAPTION>
======================================================================================
1995 1996 1997 1998 1999 2000 and thereafter
======================================================================================
<S> <C> <C> <C> <C> <C>
$1,758 $1,694 $475 $75 $76 $173
======================================================================================
</TABLE>
9. ENVIRONMENTAL MATTERS
Alagasco is in the chain of title of eight former manufactured gas plant sites,
of which it still owns four, and five manufactured gas distribution sites, of
which it still owns one. A preliminary investigation of the sites does not
indicate the present need for remediation activities. Management expects that,
should remediation of any such sites be required in the future, Alagasco's
share, if any, of such costs will not materially affect the results of
operations or financial condition of Alagasco.
10. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental information concerning cash flow activities is as follows:
<TABLE>
<CAPTION>
===================================================================================
FOR THE YEAR ENDED SEPTEMBER 30, (IN THOUSANDS) 1994 1993 1992
===================================================================================
<S> <C> <C> <C>
Interest paid, net of amount capitalized $7,762 $8,726 $8,829
Income taxes paid $9,097 $5,844 $6,823
Noncash investing activities:
Capitalized depreciation $ 155 $ 187 $ 175
Allowance for funds used during construction $ 465 $ 163 $ 50
Noncash financing activities (debt issuance costs) $ 330 $ -- $ --
===================================================================================
</TABLE>
36
<PAGE> 38
11. SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following data summarize operating results for the four quarters of 1994
and 1993. Alagasco's business is seasonal in character and strongly influenced
by weather conditions.
<TABLE>
<CAPTION>
===================================================================================
1994 FISCAL QUARTERS
(IN THOUSANDS) FIRST SECOND Third Fourth
===================================================================================
<S> <C> <C> <C> <C>
Operating revenues $78,993 $158,268 $66,070 $41,306
Operating income (loss) $ 2,945 $ 18,485 $ 3,580 $(2,711)
Net income (loss) available for common $ 696 $ 16,688 $ 1,799 $(4,287)
===================================================================================
</TABLE>
<TABLE>
<CAPTION>
===================================================================================
1993 FISCAL QUARTERS
(IN THOUSANDS) FIRST SECOND Third Fourth
===================================================================================
<S> <C> <C> <C> <C>
Operating revenues $76,866 $142,314 $69,452 $41,928
Operating income (loss) $ 2,553 $ 17,207 $ 2,693 $(2,481)
Net income (loss) available for common $ 864 $ 15,299 $ 1,016 $(4,225)
===================================================================================
</TABLE>
12. ACCOUNTING CHANGE
As discussed more fully in Note 6, the Company adopted SFAS 106, Employers'
Accounting for Postretirement Benefits Other Than Pensions, with respect to the
accrual of such costs for all employees under labor union agreements effective
October 1, 1993. The Company adopted SFAS 106 with respect to salaried
employees in a prior year.
Effective October 1, 1991, Alagasco elected early adoption of SFAS No. 109,
Accounting for Income Taxes, which was required to be adopted no later than its
fiscal year ending September 30, 1994. Changes in Alagasco's deferred income
taxes arising from the adoption have no effect on income, since the changes
represent income taxes returnable through future rates over the life of the
related assets and have been recorded as a regulatory liability on the balance
sheets.
13. TRANSACTIONS WITH RELATED PARTIES
Alagasco purchased natural gas from affiliates amounting to $4,134,000,
$4,874,000, and $6,332,000, in 1994, 1993, and 1992, respectively. These
amounts are included in gas purchased for resale. Alagasco had payables to
affiliates of $132,000 at September 30, 1994, and $1,252,000 at September 30,
1993.
37
<PAGE> 39
14. FINANCIAL INSTRUMENTS
In accordance with the requirements of SFAS No. 107 (Disclosures about Fair
Value of Financial Instruments), the estimated fair values of Alagasco's
financial instruments at September 30, 1994, were as follows:
======================================================================
Carrying Fair
AS OF SEPTEMBER 30, 1994 (IN THOUSANDS) Amount Value
======================================================================
Cash and cash equivalents $ 156 $ 156
Receivables, net of allowance account $23,047 $23,047
Short-term debt $ 4,000 $ 4,000
Long-term debt (including current maturities) $87,214 $81,021
======================================================================
The following methods and assumptions were used to estimate the fair value of
financial instruments:
- - CASH AND CASH EQUIVALENTS: Fair value was considered to be the same
as the carrying amount.
- - RECEIVABLES: The Company believes that, in the aggregate, current and
non-current net receivables were not materially different from the
fair value of those receivables.
- - SHORT-TERM DEBT: The fair value was determined to be the same as the
carrying amount.
- - LONG-TERM DEBT: The fair value of fixed-rate long-term debt was based
on the market value of debt with similar maturities and with interest
rates currently trading in the marketplace; the carrying amount of
variable rate long-term debt was assumed to approximate fair value.
38
<PAGE> 40
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS OF ENERGEN CORPORATION:
Our report on the consolidated financial statements of Energen Corporation and
subsidiaries has been incorporated by reference in this Form 10-K from page 53
of the 1994 Annual Report to Stockholders of Energen Corporation and
subsidiaries. In connection with our audits of such financial statements, we
have also audited the related financial statement schedules listed in the index
on page 16 and 17 of this Form 10-K.
In our opinion, the financial statement schedules referred to above, when
considered in relation to the basic financial statements taken as a whole,
present fairly, in all material respects the information required to be
included therein.
Coopers & Lybrand L.L.P.
Birmingham, Alabama
October 26, 1994
39
<PAGE> 41
SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
ENERGEN CORPORATION AND SUBSIDIARIES
<TABLE>
<CAPTION>
(In thousands)
=========================================================================================
BALANCE BALANCE
OCT. 1, ADDITIONS RETIREMENTS OTHER SEPT. 30,
CLASSIFICATION 1993 AT COST OR SALES CHANGES 1994
=========================================================================================
<S> <C> <C> <C> <C> <C>
UTILITY PLANT:
Organization and other
intangible plant $ 319 $ -- $ -- $ -- $ 319
Manufactured gas production
plant 98 -- -- -- 98
Storage plant 14,072 1,094 19 -- 15,147
Transmission plant 21,556 5,401 12 -- 26,945
Distribution plant 318,485 18,566 1,121 527 336,457
General plant 53,478 8,596 2,191 53 59,936
Construction in process 2,589 4,638 -- -- 7,227
Utility plant purchased 1,086 178 -- (1,264) --
Acquisition adjustment 17,432 -- -- 1,032 18,464
- -----------------------------------------------------------------------------------------
Total utility plant 429,115 38,473 3,343 348 464,593
OIL AND GAS PROPERTIES 86,077 6,456 178 -- 92,355
OTHER 21,172 1,234 8,346 -- 14,060
- -----------------------------------------------------------------------------------------
TOTAL PROPERTY, PLANT
AND EQUIPMENT $536,364 $46,163 $11,867 $ 348 $571,008
=========================================================================================
</TABLE>
40
<PAGE> 42
SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
ENERGEN CORPORATION AND SUBSIDIARIES
<TABLE>
<CAPTION>
(In thousands)
=========================================================================================
BALANCE BALANCE
OCT. 1, ADDITIONS RETIREMENTS OTHER SEPT. 30,
CLASSIFICATION 1992 AT COST OR SALES CHANGES 1993
=========================================================================================
<S> <C> <C> <C> <C> <C>
UTILITY PLANT:
Organization and other
intangible plant $ 319 $ -- $ -- $ -- $ 319
Manufactured gas production
plant 1,194 -- 1,096 -- 98
Storage plant 14,020 83 31 -- 14,072
Transmission plant 21,425 16 -- 115 21,556
Distribution plant 305,054 14,818 1,272 (115) 318,485
General plant 50,818 4,156 1,496 -- 53,478
Construction in process 655 1,934 -- -- 2,589
Utility plant purchased -- 1,086 -- -- 1,086
Acquisition adjustment 17,432 -- -- -- 17,432
- -----------------------------------------------------------------------------------------
Total utility plant 410,917 22,093 3,895 -- 429,115
OIL AND GAS PROPERTIES 65,622 21,052 597 -- 86,077
OTHER 21,020 891 739 -- 21,172
- -----------------------------------------------------------------------------------------
TOTAL PROPERTY, PLANT
AND EQUIPMENT $497,559 $44,036 $5,231 $ -- $536,364
=========================================================================================
</TABLE>
41
<PAGE> 43
SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
ENERGEN CORPORATION AND SUBSIDIARIES
<TABLE>
<CAPTION>
(In thousands)
=========================================================================================
BALANCE BALANCE
OCT. 1, ADDITIONS RETIREMENTS OTHER SEPT. 30,
CLASSIFICATION 1991 AT COST OR SALES CHANGES 1992
=========================================================================================
<S> <C> <C> <C> <C> <C>
UTILITY PLANT:
Organization and other
intangible plant $ 319 $ -- $ -- $ -- $ 319
Manufactured gas production
plant 1,211 -- 17 -- 1,194
Storage plant 12,777 1,243 -- -- 14,020
Transmission plant 20,863 -- 7 569 21,425
Distribution plant 291,967 13,659 930 358 305,054
General plant 48,659 4,045 2,111 225 50,818
Construction in process 381 274 -- -- 655
Utility plant purchased -- 1,007 -- (1,007) --
Acquisition adjustment 17,187 -- -- 245 17,432
- -----------------------------------------------------------------------------------------
Total utility plant 393,364 20,228 3,065 390 410,917
OIL AND GAS PROPERTIES 82,678 1,397 18,453 -- 65,622
OTHER 21,000 1,133 1,113 -- 21,020
- -----------------------------------------------------------------------------------------
TOTAL PROPERTY, PLANT
AND EQUIPMENT $497,042 $22,758 $22,631 $ 390 $497,559
=========================================================================================
</TABLE>
42
<PAGE> 44
SCHEDULE VI -- ACCUMULATED DEPRECIATION
ENERGEN CORPORATION AND SUBSIDIARIES
=============================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1994 1993 1992
=============================================================================
UTILITY PLANT
Balance at beginning of year $215,892 $202,684 $187,490
- -----------------------------------------------------------------------------
Additions:
Charged to expense:
Operation 309 500 508
Depreciation 16,781 15,876 15,826
Charged to clearing accounts 221 208 200
Contribution received 521 136 717
Plant acquisition 348 -- 389
Acquisition adjustment -- -- --
Acquisition adjustment amortization 851 830 820
- -----------------------------------------------------------------------------
19,031 17,550 18,460
- -----------------------------------------------------------------------------
Retirements or sales, including removal
costs, less salvage (3,596) (4,342) (3,266)
- -----------------------------------------------------------------------------
BALANCE AT END OF YEAR $231,327 $215,892 $202,684
=============================================================================
OIL AND GAS PROPERTIES
Balance at beginning of year $ 35,150 $ 29,485 $ 27,023
Additions charged to expense 8,080 5,852 6,157
Retirements (178) (187) (3,695)
Other changes -- -- --
- -----------------------------------------------------------------------------
BALANCE AT END OF YEAR $ 43,052 $ 35,150 $ 29,485
=============================================================================
OTHER
Balance at beginning of year $ 12,225 $ 10,760 $ 8,990
Additions charged to expense 1,907 2,072 2,813
Retirements (4,685) (607) (1,043)
Other changes -- -- --
- -----------------------------------------------------------------------------
BALANCE AT END OF YEAR $ 9,447 $ 12,225 $ 10,760
=============================================================================
43
<PAGE> 45
SCHEDULE VIII -- VALUATION AND QUALIFYING ACCOUNTS
ENERGEN CORPORATION AND SUBSIDIARIES
=============================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1994 1993 1992
=============================================================================
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year $1,927 $1,927 $1,943
- -----------------------------------------------------------------------------
Additions:
Charged to income: 1,825 1,656 1,419
Recoveries and adjustments 153 81 120
- -----------------------------------------------------------------------------
1,978 1,737 1,539
- -----------------------------------------------------------------------------
Less uncollectible accounts written off 1,868 1,737 1,555
- -----------------------------------------------------------------------------
BALANCE AT END OF YEAR $2,037 $1,927 $1,927
=============================================================================
44
<PAGE> 46
SCHEDULE X -- SUPPLEMENTARY INCOME STATEMENT INFORMATION
ENERGEN CORPORATION AND SUBSIDIARIES
CHARGED TO COSTS AND EXPENSES
=============================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1994 1993 1992
=============================================================================
TAXES, OTHER THAN PAYROLL AND INCOME TAXES
Utility:
City privilege $12,479 $11,350 $ 8,903
Gross receipts 7,539 7,190 6,770
Other 3,066 2,500 2,457
Oil and gas 991 955 719
Other 159 199 178
- -----------------------------------------------------------------------------
TOTAL $24,234 $22,194 $19,027
=============================================================================
Other items related to Schedule X are omitted, as the required information is
included in the financial statements or notes thereto or are not present in
amounts sufficient to require inclusion.
45
<PAGE> 47
SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
ALABAMA GAS CORPORATION
<TABLE>
<CAPTION>
(In thousands)
========================================================================================
BALANCE BALANCE
OCT. 1, ADDITIONS RETIREMENTS OTHER SEPT. 30,
CLASSIFICATION 1993 AT COST OR SALES CHANGES 1994
========================================================================================
<S> <C> <C> <C> <C> <C>
Utility Plant:
Organization and other
intangible plant $ 319 $ -- $ -- $ -- $ 319
Manufactured gas production
plant 98 -- -- -- 98
Storage plant 14,072 1,094 19 -- 15,147
Transmission plant 21,556 5,401 12 -- 26,945
Distribution plant 318,485 18,566 1,121 527 336,457
General plant 53,478 8,596 2,191 53 59,936
Construction in process 2,589 4,638 -- -- 7,227
Utility plant purchased 1,086 178 -- (1,264) --
Acquisition adjustment 17,432 -- -- 1,032 18,464
- -----------------------------------------------------------------------------------------
Total utility plant 429,115 38,473 3,343 348 464,593
Other property 83 101 -- (1) 183
- -----------------------------------------------------------------------------------------
TOTAL PROPERTY, PLANT
AND EQUIPMENT $429,198 $38,574 $3,343 $ 347 $464,776
=========================================================================================
</TABLE>
46
<PAGE> 48
SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
ALABAMA GAS CORPORATION
<TABLE>
<CAPTION>
(In thousands)
=========================================================================================
BALANCE BALANCE
OCT. 1, ADDITIONS RETIREMENTS OTHER SEPT. 30,
CLASSIFICATION 1992 AT COST OR SALES CHANGES 1993
=========================================================================================
<S> <C> <C> <C> <C> <C>
Utility Plant:
Organization and other
intangible plant $ 319 $ -- $ -- $ -- $ 319
Manufactured gas production
plant 1,194 -- 1,096 -- 98
Storage plant 14,020 83 31 -- 14,072
Transmission plant 21,425 16 -- 115 21,556
Distribution plant 305,054 14,818 1,272 (115) 318,485
General plant 50,818 4,156 1,496 -- 53,478
Construction in process 655 1,934 -- -- 2,589
Utility plant purchased -- 1,086 -- -- 1,086
Acquisition adjustment 17,432 -- -- -- 17,432
- -----------------------------------------------------------------------------------------
Total utility plant 410,917 22,093 3,895 -- 429,115
Other property 69 14 -- -- 83
- -----------------------------------------------------------------------------------------
TOTAL PROPERTY, PLANT
AND EQUIPMENT $410,986 $22,107 $3,895 $ -- $429,198
=========================================================================================
</TABLE>
47
<PAGE> 49
SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
ALABAMA GAS CORPORATION
<TABLE>
<CAPTION>
(In thousands)
========================================================================================
BALANCE BALANCE
OCT. 1, ADDITIONS RETIREMENTS OTHER SEPT. 30,
CLASSIFICATION 1991 AT COST OR SALES CHANGES 1992
========================================================================================
<S> <C> <C> <C> <C> <C>
Utility Plant:
Organization and other
intangible plant $ 319 $ -- $ -- $ -- $ 319
Manufactured gas production
plant 1,211 -- 17 -- 1,194
Storage plant 12,777 1,243 -- -- 14,020
Transmission plant 20,863 -- 7 569 21,425
Distribution plant 291,967 13,659 930 358 305,054
General plant 48,659 4,045 2,111 225 50,818
Construction in process 381 274 -- -- 655
Utility plant purchased -- 1,007 -- (1,007) --
Acquisition adjustment 17,187 -- -- 245 17,432
- -----------------------------------------------------------------------------------------
Total utility plant 393,364 20,228 3,065 390 410,917
Other property 70 -- -- (1) 69
- -----------------------------------------------------------------------------------------
TOTAL PROPERTY, PLANT
AND EQUIPMENT $393,434 $20,228 $3,065 $ 389 $410,986
=========================================================================================
</TABLE>
48
<PAGE> 50
SCHEDULE VI -- ACCUMULATED DEPRECIATION
ALABAMA GAS CORPORATION
<TABLE>
<CAPTION>
=============================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1994 1993 1992
=============================================================================
<S> <C> <C> <C>
UTILITY PLANT
Balance at beginning of year $215,892 $202,684 $187,490
- -----------------------------------------------------------------------------
Additions:
Charged to expense:
Operation 309 500 508
Depreciation 16,781 15,876 15,826
Charged to clearing accounts 221 208 200
Contribution received 521 136 717
Plant acquisition 348 -- 389
Acquisition adjustment -- -- --
Acquisition adjustment amortization 851 830 820
- -----------------------------------------------------------------------------
19,031 17,550 18,460
- -----------------------------------------------------------------------------
Retirements or sales, including removal
costs, less salvage (3,596) (4,342) (3,266)
- -----------------------------------------------------------------------------
BALANCE AT END OF YEAR $231,327 $215,892 $202,684
=============================================================================
</TABLE>
49
<PAGE> 51
SCHEDULE VIII -- VALUATION AND QUALIFYING ACCOUNTS
ALABAMA GAS CORPORATION
=============================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1994 1993 1992
=============================================================================
ALLOWANCE FOR DOUBTFUL ACCOUNTS
Balance at beginning of year $1,800 $1,800 $1,800
- -----------------------------------------------------------------------------
Additions:
Charged to income: 1,805 1,613 1,370
Recoveries and adjustments 263 78 113
- -----------------------------------------------------------------------------
2,068 1,691 1,483
- -----------------------------------------------------------------------------
Less uncollectible accounts written off 1,868 1,691 1,483
- -----------------------------------------------------------------------------
BALANCE AT END OF YEAR $2,000 $1,800 $1,800
=============================================================================
50
<PAGE> 52
SCHEDULE X -- SUPPLEMENTARY INCOME STATEMENT INFORMATION
ALABAMA GAS CORPORATION
CHARGED TO COSTS AND EXPENSES
=============================================================================
YEARS ENDED SEPTEMBER 30, (IN THOUSANDS) 1994 1993 1992
=============================================================================
TAXES, OTHER THAN PAYROLL AND INCOME TAXES
Utility:
City privilege $12,479 $11,350 $ 8,903
Gross receipts 7,539 7,190 6,770
Other 3,066 2,500 2,457
- -----------------------------------------------------------------------------
TOTAL $23,084 $21,040 $18,130
=============================================================================
Other items related to Schedule X are omitted, as the required information is
included in the financial statements or notes thereto or are not present in
amounts sufficient to require inclusion.
51
<PAGE> 1
EXHIBIT 10(f)
AMENDMENT TO EXECUTIVE RETIREMENT SUPPLEMENT AGREEMENT
(EXECUTIVE: )
THIS AMENDMENT, made and entered into effective as of June 22,
1994 by ENERGEN CORPORATION, an Alabama corporation (the "Company");
WHEREAS, the Company and the above-referenced Executive are
parties to that certain Executive Retirement Supplement Agreement dated
________________________ (the "Agreement"); and
WHEREAS, pursuant to Article III of the Agreement, the Company
desires to amend the Agreement as set forth below;
NOW, THEREFORE, Section 1.5 of the Agreement is hereby amended
and restated in its entirety to read as follows:
Compensation: The sum of A plus B. For purposes of this
definition, A shall equal the average aggregate monthly basic pay from
all Employers for the 36 consecutive calendar months during which the
Executive had the highest average monthly basic pay out of the 60
calendar months immediately preceding the Severance Date. For
purposes of this definition, B shall equal C divided by 12, where C
equals the average of the Executive's three highest annual cash
incentive awards under the Energen Annual Incentive Compensation Plan
(or successor annual cash incentive plan) for the five Company fiscal
years immediately preceding the earlier of (i) the fiscal year during
which the Severance Date occurs or (ii) the fiscal year during which
the Executive's 61st birthday occurs.
IN WITNESS WHEREOF, the Company has caused this Amendment to
be executed by its duly authorized officer, all as of the day and year first
above written.
ENERGEN CORPORATION
By __________________________
Its Chairman and CEO
Acknowledged and Agreed
__________________________
Executive
<PAGE> 1
EXHIBIT 10(M)
ENERGEN CORPORATION
ANNUAL INCENTIVE COMPENSATION PLAN
<TABLE>
<CAPTION>
Article Description Page
- ------- ----------- ----
<S> <C> <C>
I. Purpose 1
II. Policy 1
III. Scope 1
IV. Terms and Definitions 1
V. Control Responsibility 3
VI. Plan Design 3
VII. Deferral Arrangements 5
VIII. Participant Eligibility and 6
Partial Year Awards
IX. Taxes and Effect on Other Benefits 7
X. Termination And/Or Amendments 7
XI. Assignments or Transfers 7
XII. Payment of Awards 8
Attachment Fiscal Year Potential Incentive
</TABLE>
Revised 5/90
As amended effective October 1, 1993.
<PAGE> 2
ENERGEN CORPORATION
ANNUAL INCENTIVE COMPENSATION PLAN
I. PURPOSE: Attract, retain and motivate key management personnel while
promoting a team spirit and the pay for performance concept.
II. POLICY: It is the policy of Energen Corporation and its subsidiary
companies to provide an incentive compensation plan which rewards superior
performance that benefits:
o Stockholders (earnings plus capital appreciation)
o Customers (quality service and products)
o Management (income)
III. SCOPE: This Incentive Compensation Plan is applicable to key executive
management personnel as recommended by the Chief Executive Officer and
approved by the Officer Review Committee of the Energen Board of
Directors.
IV. TERMS AND DEFINITIONS
4.01 The Plan - The Annual Incentive Compensation Plan approved by the
Energen Board of Directors in April 1986.
4.02 Board of Directors - The Board of Directors of Energen Corporation.
4.03 ORC - The Officer Review Committee of the Board of Directors.
4.04 Energen Performance - The Energen financial performance objectives
approved by the ORC.
4.05 Subsidiary Performance - Selected performance objectives (earnings
and other) for each subsidiary company or group of executives.
4.06 Individual Performance - Individual participant performance against
previously established individual short-term objectives.
<PAGE> 3
4.07 Participant - An executive employee recommended by the CEO and
approved by the ORC to participate in the Plan.
4.08 Plan Year - Fiscal year October 1 through September 30.
4.09 Salary - The actual salary earned by the participant during the
plan year.
4.10 Weather Adjusted - The actual financial performance attributable to
the gas distribution line of business will be adjusted to reflect
performance in a normal weather year.
4.11 Base Bonus Factor - A number expressed in terms of "percent of
salary" that each participant is potentially eligible to receive based on
Energen performance (see Attachment).
4.12 Floor - The Energen financial performance objective below which no
incentive awards will be made regardless of subsidiary or individual
performance. The "floor" is not weather adjusted.
4.13 Target - The Energen financial performance "stretch" objective. The
target is weather adjusted.
4.14 Maximum - The maximum is controlled by the individual maximum caps
(see Section 6.05 and Attachment) and Energen net income (see Bonus Pool
footnote on Attachment).
4.15 Potential Bonus Pool - The potential amount of money available for
distribution for different levels of Energen performance results (see
Attachment).
4.16 Incentive Award - The annual cash incentive (or bonus) payment
based on Energen, subsidiary and individual performance.
4.17 Election - A voluntary election to defer payment of an award in
accordance with Article VII.
<PAGE> 4
V. CONTROL RESPONSIBILITY
5.01 The Board of Directors will approve Energen Performance objectives
on recommendation of the ORC on an annual basis.
5.02 The ORC will administer the Plan which will include approval of:
a. Subsidiary performance measures for the Energen CEO and
other Energen staff participants as a group.
b. Individual performance measures and the individual incentive
awards for the CEO and all participants reporting directly
to the CEO.
c. Evaluation of subsidiary performance recommended by the CEO.
5.03 The Energen CEO will approve:
a. The establishment of subsidiary performance measures in
conjunction with the subsidiary presidents.
b. The individual performance measures and the individual
incentive awards for all other participants.
VI. PLAN DESIGN
6.01 Potential Bonus Pool - The Potential Bonus Pool is expressed as a
pool of dollars available for distribution based on Energen Performance as
covered in Section 6.02 (see Attachment).
6.02 Energen Performance - Base Bonus Factor - Energen Performance
includes financial objectives for floor, target, and maximum award levels.
Energen Performance therefore dictates the Base Bonus Factor (see
Attachment) which is used in the following formula to determine the
individual incentive award:
<PAGE> 5
Incentive Award = Salary X Base Bonus Factor X
Subsidiary Performance Factor X
Individual Performance Factor
6.03 Subsidiary Performance - The CEO in consultation with the subsidiary
presidents will establish objective criteria for evaluating subsidiary
performance. In determining the individual incentive award for each
participant, the Base Bonus Factor can therefore be adjusted for
subsidiary performance based on the following:
<TABLE>
<CAPTION>
Performance Factor
Examples Of -------------------
Subsidiary Performance Measures Range of Adjustment
---------- -------------------- -------------------
<S> <C> <C>
Energen Consolidated Net Income .50 - 1.50
Executive and Market/Book Ratio
Group
Alagasco AGC Net Income .75 - 1.25
All Other Financial and
Operating Objectives (Customer
Satisfaction, Marketing, Gas
Supply, Growth, etc.) .50 - 1.50
Taurus Net Income, Finding Cost .50 - 1.50
and Reserve Additions
Others As Appropriate .50 - 1.50
</TABLE>
The subsidiary performance factor is determined by objectively measuring
results against established performance objectives and used in the formula
to determine the individual incentive award:
Incentive Award = Salary X Base Bonus Factor X
Subsidiary Performance Factor X
-----------------------------
Individual Performance Factor
<PAGE> 6
6.04 Individual Performance - Participants must meet or exceed certain
individual performance criteria prior to earning an incentive award.
Participants will establish with their supervisor key objectives, both
strategic and operational, for the fiscal year. The individual
participant's incentive award will be adjusted based on the achievement of
these objectives.
Each objective will be assigned a weight. The sum will be equal to 100.
At the end of the plan year the participant's overall performance on such
objectives will be rated as follows:
a. Unacceptable - 0
b. Effective - 1.0
c. Highly Effective - 1.5
d. Outstanding - 2.0
The Individual Performance Factor is found by:
Sum Total of = Objective Weight X Rating
---------------------------
100
The performance factor is prorated for levels of performance between the
measures identified and is used in the formula to determine individual
incentive awards:
Incentive award = Salary X Base Bonus Factor X
Subsidiary Performance Factor X
Individual Performance Factor
-----------------------------
6.05 Control Measure - Individual Maximum Bonus Potential - Maximum
individual awards have been established for each group of participants
(see Attachment).
VII. DEFERRAL ARRANGEMENTS:
7.01 A participant may elect to defer an award payment by filing an
election with the Company no later than March 31 of the plan year.
7.02 A participant will be allowed to defer all or part of the incentive
award in 25% increments to be paid out over a four-year period.
<PAGE> 7
7.03 The election shall be made in writing in a form letter prescribed by
the Company and shall state:
a. that the participant wishes to make an election to defer
payment of any award that shall be earned in the plan year;
b. the percentage of the award to be deferred; and
c. the method of payment desired not to exceed four years.
7.04 Once made this election may not be revoked at any time during the
plan year. Any payout of the deferred award prior to the time specified
in the participant's original election will be solely at the discretion of
the Company.
7.05 The deferred award will accumulate interest at a rate equal to the
90-day Treasury Bill rate. Interest will be computed as if credited from
the date of award and will be compounded monthly. The rate in effect on
the first business day of the month shall be the rate used.
7.06 When a participant terminates employment with the Company, the
participant shall be entitled to receive the entire amount reflected in
the participant's deferred account. In the event of the death of a
participant the entire amount reflected in the participant's deferred
account will be paid to the deceased's beneficiary as designated on the
deceased's group life insurance benefit with the Company.
VIII. PARTICIPANT ELIGIBILITY AND PARTIAL YEAR AWARDS
8.01 A participant in this Plan will be a key executive of the Company
recommended by the Chief Executive Officer and approved by the Officer
Review Committee.
8.02 A participant must be approved and eligible for the Plan at the
beginning of the plan year. Prospective participants hired or promoted
during the plan year will be handled on an individual basis.
<PAGE> 8
8.03 A participant who vacates an eligible position during the plan year
due to retirement, disability or death will be included in the Plan on a
prorata basis (number of months worked during the year divided by 12).
8.04 Payments for partial year participants will be made at the end of
the plan year in conjunction with all other awards.
IX. TAXES AND EFFECT ON OTHER BENEFITS
9.01 Any award shall be considered as compensation for tax purposes and
there shall be deducted from the payment the amount of any tax required by
any governmental authority.
9.02 Award payments will not be considered as wages, salaries or
compensation under any of the employee fringe benefit plans of the
Company.
X. TERMINATION AND/OR AMENDMENTS
10.1 The Board of Directors may terminate the Plan at any time and may
from time to time amend the Plan. Such amendments will not impair any
rights to payments which have been deferred prior to termination or
amendment.
XI. ASSIGNMENTS OR TRANSFER
11.1 Neither the participant, participant's beneficiary, nor the
participant's personal representative shall have any rights to commute,
sell, assign, transfer or otherwise convey the right to receive any
payments or awards under this Plan. Such payments or awards are
non-assignable and non-transferable and any attempt to assign or transfer
payments or awards shall be void and have no effect.
XII. PAYMENT OF AWARDS
12.1 At the end of the plan year the annual incentive awards and payments
will be made by payroll check as soon as practicable after all evaluations
and approvals are complete.
<PAGE> 9
The foregoing notwithstanding, upon written election of a Group I participant
delivered prior to the time that the amount of an award under this Plan becomes
ascertainable and due, and approval of such election by the ORC, such
participant may elect to receive payment of a specified portion or all of an
award under the Plan in the form of stock options issued under the Company's
1988 Stock Option Plan (subject to availability of options under the 1988 Stock
Option Plan). For purposes of calculating the appropriate number of options
for issuance pursuant to such an election, the options shall be valued using
the binomial option pricing model or such other comparable method approved by
the ORC.
<PAGE> 1
EXHIBIT 13
Financial Review
Management's Discussion and Analysis of Results of Operations and Financial
Condition
RESULTS OF OPERATIONS
CONSOLIDATED NET INCOME
Energen achieved record net income for the fourth year in a row with earnings
totaling $23.8 million ($2.19 per share) compared to fiscal 1993 net income of
$18.1 million ($1.77 per share). Included in the Company's current-year
earnings are one-time gains of $2 million from the sale of its propane assets
and the reduction of its investment in high-temperature combustion technology.
Excluding these gains, Energen would have achieved record net income of $21.8
million ($2.01 per share). Energen reported earnings of $16.6 million ($1.64
per share) in 1992. In that year, Energen adopted Statement of Financial
Accounting Standard (SFAS) 109, Accounting for Income Taxes, and the cumulative
effect of that change (10 cents per share) was reflected.
1994 VS. 1993: Alagasco, Energen's natural gas distribution company, earned
record net income of $14.9 million compared with $13 million in fiscal 1993.
The utility's investment in underground storage working gas in November 1993
increased the equity upon which Alagasco was able to earn its allowed return.
The utility's return on average equity was 13.2 percent. Customer bills were
not increased by the storage working gas investment as it represented a
transfer of costs from the pipeline supplier to Alagasco.
Taurus Exploration Inc. (Taurus), Energen's oil and gas exploration and
production company, reported net income of $6.5 million compared with fiscal
1993 earnings of $5.1 million. The 27 percent increase largely was associated
with increased conventional gas activities as production more than doubled to
5.5 Bcf. Taurus also benefited from increased coalbed methane operating fees.
1993 VS. 1992: Taurus was the primary contributor to Energen's improved
earnings. Taurus's net income of $5.1 million more than doubled its 1992 income
from current operations of $2.3 million, largely due to increased coalbed
methane operating fees and consulting revenues, decreased exploration expenses,
and higher natural gas prices.
Alagasco reported record net income of $13 million, an increase of $0.6 million
over the prior year. The utility earned near its allowed range of return on an
increased level of equity which represented investment needed to meet the
demands of a growing service area. Contributions from the Company's group of
other activities decreased from the previous year primarily due to reduced
income from gathering services and propane activities.
OPERATING INCOME
CONSOLIDATED: Consolidated operating income in 1994, 1993, and 1992 totaled
$35.9 million, $30.3 million, and $22.8 million, respectively. The notable
increase over the prior year primarily is associated with the utility, as
Alagasco's operating income has tended to increase in a manner consistent with
its opportunity for earning within its allowed range of return on equity. The
more pronounced improvement in 1994 operating income is a direct result of its
investment in underground working storage gas which was financed, in part,
through the issuance of equity. Taurus again had a strong positive influence on
Energen's operating income as it focused on expanding its conventional oil and
gas operations and capitalizing on its coalbed methane expertise.
ALABAMA GAS CORPORATION: Alagasco generates revenues through the sale and
transportation of natural gas. Shifts between transportation and sales gas can
cause large variations in natural gas revenues since the transportation rate
does not contain an amount representing the cost of gas. Alagasco's rate
structure, however, allows similar margins on transported and sales gas;
therefore, operating income is not adversely affected. Alagasco's gross natural
gas sales revenues totaled $315.3 million, $303.2 million, and $285.6 million
in 1994, 1993, and 1992, respectively. Rate relief created the majority of the
increase in 1994. The increase for 1993 primarily was due to higher gas costs,
increased sales to core customers, and rate relief, partially offset by
decreased sales to large commercial and industrial customers who shifted to
transportation.
<PAGE> 2
<TABLE>
<CAPTION>
====================================================================================================================================
Years ended September 30,
(dollars in thousands) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Gross natural gas sales revenues $ 315,317 $ 303,178 $ 285,637
Cost of natural gas (188,592) (187,800) (176,411)
Revenue taxes (20,018) (18,540) (15,674)
- ------------------------------------------------------------------------------------------------------------------------------------
Net natural gas sales margin 106,707 96,838 93,552
Net natural gas transportation margin 29,320 27,382 25,089
- ------------------------------------------------------------------------------------------------------------------------------------
Net natural gas sales and transportation
margin $ 136,027 $124,220 $ 118,641
====================================================================================================================================
Natural gas sales volumes (MMcf)
Residential 31,254 30,957 29,119
Commercial and industrial--small 13,536 13,853 13,860
Commercial and industrial--large 106 282 2,654
- ------------------------------------------------------------------------------------------------------------------------------------
Total natural gas sales volumes 44,896 45,092 45,633
Natural gas transportation volumes (MMcf) 52,635 49,346 46,235
====================================================================================================================================
Total deliveries (MMcf) 97,531 94,438 91,868
====================================================================================================================================
</TABLE>
Residential sales volumes, which tend to fluctuate as a function of weather,
remained relatively stable in the current year following a 6 percent increase
in 1993. Weather in Alagasco's service area was 2 percent colder than normal in
1994, 1 percent colder than normal in 1993, and 6 percent warmer than normal in
1992. While weather typically affects customers' usage of natural gas,
Alagasco's operating margins remain unaffected due to a real-time temperature
adjustment provision which lets Alagasco adjust customer bills monthly to
reflect changes in usage due to variances from normal temperatures.
Sales and transportation volumes to commercial, industrial and municipal
customers totaled 66.3 Bcf in 1994, 63.5 Bcf in 1993, and 62.7 Bcf in 1992. The
4 percent increase in 1994 represents the addition of several industrial
customers. Volumes were relatively stable in 1993.
The utility's 1994 unit cost of gas virtually was unchanged from 1993. Firm and
spot market prices were lower on stable sales volumes; however, the resulting
decrease largely was offset by the inclusion in the current year of gas supply
realignment costs incurred in connection with the implementation of FERC Order
636. In 1993 the increased cost of firm and spot market gas supplies resulted
in a 7 percent increase in the unit cost of gas.
Operations and maintenance (O&M) expenses increased 9 percent and 7 percent in
1994 and 1993, respectively, primarily due to increases in labor and related
expenses. Of the 9 percent increase in 1994, 3 percent related to the adoption
of SFAS 106, Employers' Accounting For Postretirement Benefits Other Than
Pensions, for employees under labor union agreements. On a per customer basis,
the remainder of the O&M expense increase fell within the index range
established by the Alabama Public Service Commission (APSC). In 1993 the
increase in O&M expense per customer exceeded the APSC index range and
necessitated the return to customers of a portion of the excess.
Depreciation expense rose 4 percent in 1994 consistent with growth in the
utility's depreciable base. In 1993 depreciation expense remained stable as the
increases in depreciable base were offset by lower average depreciation rates
resulting from a change in both APSC-established rates and the composition of
depreciable assets. Alagasco's expense for taxes other than income primarily
reflects various state and local business taxes as well as payroll-related
taxes; state and local business taxes are generally based on gross receipts and
fluctuate accordingly.
As discussed more fully in Note 3, Alagasco is subject to regulation by the
APSC, which is expected to consider renewal of the utility's rate-setting
mechanism following the completion of its review of certain mandates under the
Energy Policy Act of 1992. Changes, if any, to the utility's present
rate-setting assumptions or provisions could have an impact on its net income
for 1995 and beyond.
TAURUS: Taurus continued to focus on its conventional oil and gas strategy in
1994 as evidenced by its mix of conventional and coalbed methane production.
Conventional oil and gas constituted 64 percent of total 1994 production
compared to 49 percent and 25 percent in 1993 and 1992, respectively.
Accordingly, the $5.8 million increase in natural gas production revenues
<PAGE> 3
in the current year almost exclusively was due to higher conventional
production which more than doubled the prior year's levels. Oil revenues
declined slightly primarily as a result of a 17 percent decrease in oil prices.
In 1993 natural gas revenues increased $1.1 million largely due to a 13 percent
increase in average natural gas sales prices. The $0.9 million increase in oil
revenue primarily was due to a 41 percent increase in volumes.
<TABLE>
<CAPTION>
====================================================================================================================================
Years ended September 30,
(dollars in thousands, except unit price) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Revenues
Natural gas production $ 17,292 $ 11,449 $ 10,364
Oil production 2,725 3,484 2,559
Operating and consulting fees 5,194 4,954 2,795
- ------------------------------------------------------------------------------------------------------------------------------------
Total Revenues $ 25,211 $ 19,887 $ 15,718
====================================================================================================================================
Production volumes
Natural gas (MMcf) 9,169 6,245 6,415
Oil (MBbl) 191 204 145
====================================================================================================================================
Average unit sales price
Natural gas (per Mcf) $ 1.89 $ 1.83 $ 1.62
Oil (per Bbl) $ 14.25 $ 17.09 $ 17.65
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
Increased operating fees virtually were offset by decreased consulting fees in
the current year. Operating fees represent a percentage of net proceeds on
certain coalbed methane properties, as defined by the related operating
agreements, and vary with changes in natural gas prices, production volumes and
operating expenses. The $1 million increase in operating fees resulted from
increased production and the addition of TECO Coalbed Methane's CDM Project in
late 1993. Consulting fees decreased $0.8 million due to the completion of
several projects partially offset by revenue from the new strategic alliance
with Conoco Inc. For 1993 operating fees and consulting revenues increased $2.2
million. The $1.4 increase in operating fees primarily resulted from increased
natural gas prices and a new 47-well program. Consulting fees were $0.8 million
higher due to the addition of new projects.
The $2 million increase in operations expense over the prior year primarily was
due to increased exploration and lease operating expenses. Exploration expense
exceeded the prior year by $1.3 million due to the expansion of Taurus's
exploratory efforts. Operating expenses for several offshore properties
brought on-line in late 1993 and early 1994 caused the increased lease
operating expenses. A $3.8 million decrease in 1993 primarily resulted from
lower exploration expense and lower labor and related expenses.
Depreciation, depletion, and amortization increased 30 percent in 1994 due to a
significant increase in production volumes. The depletion rate (78 cents) was
unchanged from the previous year. A 13 percent decrease in 1993 over the prior
year primarily was the result of decreased depletion rates (84 cents).
OTHER ACTIVITIES AND INTERCOMPANY ELIMINATIONS: Operating income from
Energen's group of other activities increased in 1994 due to increased
contribution from propane activities prior to the asset sale and increased
contribution from its merchandising operations. The 1993 decrease primarily
reflects reduced contribution from its gathering services and propane
activities.
Intercompany revenue eliminations for 1994, 1993, and 1992 totaled $8.1
million, $8.3 million, and $9.6 million, respectively, and vary primarily based
on intercompany natural gas and merchandising sales.
NON-OPERATING ITEMS
CONSOLIDATED: Interest expense in 1994 increased 7 percent over 1993.
Increases resulting from the issuance of $50 million in medium-term notes in
1994 and the inclusion for a full year of the Series 1993 Notes were offset in
part by decreased average short-term borrowings. Interest expense increased
only slightly in 1993 as the effects of increased average short-term borrowings
virtually were offset by a slight decrease in average long-term debt and
declining interest rates.
Total other expense decreased $3.2 million in the current year primarily due to
the inclusion of one-time pre-tax gains associated
<PAGE> 4
with the sale of the Company's propane assets ($2.1 million) and the sale of
the Company's investment in equity securities ($1.5 million). An increase of
$2.1 million in 1993 reflects the inclusion in 1992 of a one-time gain from the
sale of a portion of Taurus's coalbed methane properties.
The Company's effective tax rates in 1994, 1993, and 1992 were lower than
statutory federal tax rates in each of those years primarily due to the
recognition of nonconventional fuel tax credits and the amortization of
investment tax credits. Income tax expense increases in both years primarily
resulted from increased consolidated pre-tax income. In 1993 a 25 percent
decrease in the recognition of nonconventional fuel tax credits over the
previous year also contributed to the increase. The Company's effective tax
rates are expected to remain lower than statutory federal rates in the near
future as all tax credits generated are expected to be recognized.
FINANCIAL POSITION AND LIQUIDITY
The Company's net cash from operating activities totaled $34.3 million, $40.4
million, and 30.3 million in 1994, 1993, and 1992, respectively. Operating cash
flows in 1994 were strongly influenced by the implementation of Order 636 and
the resulting purchase of storage gas by Alagasco. The initial investment in
November 1993 was approximately $28 million and averaged $21 million over the
full year; by year-end, the total capital employed related to storage gas was
$24 million. Offsetting this investment was the timing of the recovery of gas
supply adjustment costs. In addition, cash flow was affected by fluctuations in
other receivables and payables which are generally the result of timing.
Cash used in investing activities decreased $13.5 million in 1994 to $28
million. The proceeds received for both the sale of assets and equity
securities totaled $13.4 million and effectively offset the cash used for
capital additions, which was comparable in both years. Net cash used in 1993
increased to $41.5 million primarily as a result of significantly increased oil
and gas expenditures associated with Taurus's investment in conventional
producing properties.
Cash provided by financing activities in 1994 was $6.2 million. Proceeds from
the issuance of 550,000 shares of Energen common stock in November totaled
$13.5 million and were used to help fund the purchase of underground storage
working gas. Additionally, Alagasco issued $50 million of medium-term notes to
fund the balance of the storage investment, redeem its 8.75 percent debentures,
reduce its short-term debt, and fund additional capital needs. The notes
offered investors a combination of interest rates and investment periods: from
5.4 percent to 7.2 percent for notes redeemable December 1, 1998, to December
15, 2023. In 1993 cash provided by financing activities was $5.7 million as
compared to a use of $14.9 million in 1992. The Series 1993 Notes provided
$14.6 million which was used to repay short-term indebtedness incurred in the
acquisition of conventional oil and gas reserves and for coalbed methane
development activities. The utility used $15.6 million in short-term borrowings
to redeem the remainder of its Series F and Series G First Mortgage Bonds and
its preferred stock in addition to its scheduled payments.
CAPITAL EXPENDITURES
NATURAL GAS DISTRIBUTION: During the last three fiscal years, Alagasco has
invested $80.8 million for capital projects; $68.4 million was spent on normal
expansion replacements and support of its distribution system; $6.4 million was
used in connection with the development of a new customer information system;
$3.8 million was used to improve gas availability; and $2.2 million was used to
purchase two municipal gas distribution systems.
<TABLE>
<CAPTION>
====================================================================================================================================
Years ended September 30,
(in thousands) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Capital expenditures for:
Renewals, replacements, system
expansion and other $ 30,264 $ 19,438 $ 18,658
Additions to improve gas availability 1,644 1,569 563
Municipal gas system acquisitions 178 1,086 1,007
Customer information system 6,387 - -
- ------------------------------------------------------------------------------------------------------------------------------------
Total $ 38,473 $ 22,093 $ 20,228
====================================================================================================================================
</TABLE>
<PAGE> 5
EXPLORATION AND PRODUCTION: Taurus spent $35.5 million for capital projects
over the last three years. Of that total, $4.9 million was charged to income as
exploration expense. Expenditures for conventional oil and gas activities over
the last three years totaled $29.8 million and primarily reflect Taurus's
investment in proved property acquisitions and exploration and development of
offshore natural gas properties. Expenditures for nonconventional oil and gas
activities for the last three years totaled $4 million.
<TABLE>
<CAPTION>
====================================================================================================================================
Years ended September 30,
(dollars in thousands) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Capital and exploration expenditures for:
Conventional oil and gas $ 7,853 $ 20,777 $ 1,203
Nonconventional gas 217 1,007 2,742
Other 900 397 441
- ------------------------------------------------------------------------------------------------------------------------------------
Total $ 8,970 $ 22,181 $ 4,386
====================================================================================================================================
Exploration expenditures charged to
income (included above) for:
Conventional oil and gas $ 1,577 $ 731 $ 504
Nonconventional gas 37 1 2,044
- ------------------------------------------------------------------------------------------------------------------------------------
Total $ 1,614 $ 732 $ 2,548
====================================================================================================================================
</TABLE>
OTHER ACTIVITIES: Capital expenditures by Energen's other activities totaled
$1.5 million during the last three fiscal years and included two propane
acquisitions in 1992.
FUTURE CAPITAL EXPENDITURES AND LIQUIDITY
Capital and exploration expenditures could approximate $66 million in 1995,
excluding municipal gas system acquisitions, and primarily represent additions
for normal distribution system expansion, the development of a new customer
information system at Alagasco, and oil and gas development activities. In
addition, the Company will maintain an investment in storage working gas which
is anticipated to average $19 million in 1995. The Company anticipates funding
these capital requirements through internally generated capital and the
utilization of short-term credit facilities. Energen has short-term credit
facilities totaling $110 million available for working capital needs, with $6
million and $40 million employed at September 30, 1994 and 1993, respectively.
The Company's oil and gas subsidiary periodically enters into futures contracts
to hedge its exposure to price fluctuations on oil and gas production. Under
this program, Taurus has entered into futures contracts for the sale of 5 Bcf
of its fiscal 1995 gas production at an average contract price of $2.17 and for
the sale of 160,000 barrels of its oil production at an average contract price
of $18.61.
As previously discussed, the Company anticipates its effective income tax rates
to remain lower than statutory federal tax rates due to the recognition of
nonconventional fuel tax credits; the Company will receive cash benefit for a
portion of those tax credits in the future due to alternative minimum tax
provisions.
<PAGE> 6
Consolidated Statements Of Income
Energen Corporation and Subsidiaries
<TABLE>
<CAPTION>
====================================================================================================================================
Years ended September 30, (in thousands, except share data) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
OPERATING REVENUES
Natural gas distribution $ 344,637 $ 330,560 $ 310,726
Oil and gas production 25,211 19,887 15,718
Other 15,401 14,926 15,099
Intercompany eliminations (8,176) (8,257) (9,561)
- ------------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 377,073 357,116 331,982
- ------------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of gas 184,458 182,925 170,079
Operations 91,787 84,050 81,707
Maintenance 9,469 9,235 9,067
Depreciation, depletion and amortization 28,000 25,289 26,274
Taxes, other than income taxes 27,451 25,350 22,062
- ------------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 341,165 326,849 309,189
- ------------------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 35,908 30,267 22,793
- ------------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE)
Interest expense, net of amounts capitalized (11,345) (10,605) (10,415)
Dividends on preferred stock of subsidiary - (70) (85)
Gain on sale of assets 2,142 - 2,763
Other, net 3,657 1,897 1,013
- ------------------------------------------------------------------------------------------------------------------------------------
Total other income (expense) (5,546) (8,778) (6,724)
- ------------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 30,362 21,489 16,069
Income taxes 6,611 3,408 382
- ------------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE 23,751 18,081 15,687
Cumulative effect of change in accounting principle - - 941
====================================================================================================================================
NET INCOME $ 23,751 $ 18,081 $ 16,628
====================================================================================================================================
EARNINGS PER AVERAGE COMMON SHARE
Income before cumulative effect $ 2.19 $ 1.77 $ 1.54
Cumulative effect of change in accounting principle - - .10
- ------------------------------------------------------------------------------------------------------------------------------------
Net income $ 2.19 $ 1.77 $ 1.64
====================================================================================================================================
AVERAGE COMMON SHARES OUTSTANDING 10,833,619 10,236,926 10,168,111
====================================================================================================================================
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
<PAGE> 7
Consolidated Balance Sheets
Energen Corporation and Subsidiaries
<TABLE>
<CAPTION>
====================================================================================================================================
As of September 30, (in thousands) 1994 1993
====================================================================================================================================
<S> <C> <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Utility plant $ 464,593 $ 429,115
Less accumulated depreciation 231,327 215,892
- ------------------------------------------------------------------------------------------------------------------------------------
Utility plant, net 233,266 213,223
- ------------------------------------------------------------------------------------------------------------------------------------
Oil and gas properties, successful efforts method 92,355 86,077
Less accumulated depreciation, depletion and amortization 43,052 35,150
- ------------------------------------------------------------------------------------------------------------------------------------
Oil and gas properties, net 49,303 50,927
- ------------------------------------------------------------------------------------------------------------------------------------
Other property, net 4,613 8,947
- ------------------------------------------------------------------------------------------------------------------------------------
Total property, plant and equipment, net 287,182 273,097
- ------------------------------------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents 27,526 15,008
Accounts receivable, net of allowance for doubtful accounts of $2,037 in 1994 and
$1,927 in 1993 34,145 36,181
Inventories, at average cost
Storage gas inventory 24,363 -
Materials and supplies 7,589 8,957
Liquified natural gas in storage 3,349 3,636
Deferred gas costs 1,460 2,966
Deferred income taxes 7,542 4,090
Prepayments and other 3,117 4,034
- ------------------------------------------------------------------------------------------------------------------------------------
Total current assets 109,091 74,872
- ------------------------------------------------------------------------------------------------------------------------------------
OTHER ASSETS
Notes receivable 3,911 6,798
Deferred charges and other 11,130 15,918
- ------------------------------------------------------------------------------------------------------------------------------------
Total other assets 15,041 22,716
- ------------------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 411,314 $ 370,685
====================================================================================================================================
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
<PAGE> 8
<TABLE>
<CAPTION>
====================================================================================================================================
As of September 30, (in thousands) 1994 1993
====================================================================================================================================
<S> <C> <C>
CAPITAL AND LIABILITIES
CAPITALIZATION
Preferred stock, cumulative, $0.01 par value, 5,000,000 shares authorized $ - $ -
Common shareholders' equity
Common stock, $0.01 par value; 30,000,000 shares authorized, 10,917,904 shares
outstanding in 1994 and 10,320,317 shares outstanding in 1993 109 103
Premium on capital stock 81,073 66,368
Capital surplus 2,802 2,802
Retained earnings 83,042 71,040
- ------------------------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 167,026 140,313
Long-term debt 118,302 85,852
- ------------------------------------------------------------------------------------------------------------------------------------
Total capitalization 285,328 226,165
- ------------------------------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Long-term debt due within one year 10,123 5,043
Notes payable to banks 6,000 40,000
Accounts payable 27,480 27,609
Accrued taxes 13,083 9,656
Customers' deposits 17,462 16,719
Amounts due customers 11,734 5,105
Accrued wages and benefits 9,662 8,054
Other 15,129 13,232
- ------------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 110,673 125,418
- ------------------------------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes 1,706 480
Accumulated deferred investment tax credits 4,590 5,077
Other 9,017 13,545
- ------------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 15,313 19,102
- ------------------------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES - -
- ------------------------------------------------------------------------------------------------------------------------------------
TOTAL CAPITAL AND LIABILITIES $ 411,314 $ 370,685
====================================================================================================================================
</TABLE>
<PAGE> 9
Consolidated Statements Of Shareholders Equity
Energen Corporation and Subsidiaries
<TABLE>
<CAPTION>
====================================================================================================================================
(In thousands, except share amounts)
====================================================================================================================================
Common Stock
-----------------------
Number of Par Premium on Capital Retained
Shares Value Capital Stock Surplus Earnings
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
BALANCE AT SEPTEMBER 30, 1991 10,104,482 $ 101 $ 61,745 $ 2,802 $ 57,347
Net income 16,628
Shares issued for:
Dividend reinvestment plan 8,483 153
Employee benefit plans 69,633 1 1,347
Cash dividends--$1.01 per share (10,266)
- ------------------------------------------------------------------------------------------------------------------------------------
BALANCE AT SEPTEMBER 30, 1992 10,182,598 102 63,245 2,802 63,709
Net income 18,081
Shares issued for:
Dividend reinvestment plan 20,862 474
Employee benefit plans 116,857 1 2,649
Cash dividends--$1.05 per share (10,750)
- ------------------------------------------------------------------------------------------------------------------------------------
BALANCE AT SEPTEMBER 30, 1993 10,320,317 103 66,368 2,802 71,040
Net income 23,751
Shares issued for:
Stock offering 550,000 6 13,531
Dividend reinvestment plan 7,717 181
Employee benefit plans 39,870 993
Cash dividends -- $1.09 per share (11,749)
- ------------------------------------------------------------------------------------------------------------------------------------
BALANCE AT SEPTEMBER 30, 1994 10,917,904 $ 109 $ 81,073 $ 2,802 $ 83,042
====================================================================================================================================
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
<PAGE> 10
Consolidated Statements Of Cash Flows
Energen Corporation and Subsidiaries
<TABLE>
<CAPTION>
====================================================================================================================================
Years ended September 30, (in thousands) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income $ 23,751 $ 18,081 $ 16,628
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, depletion and amortization 28,000 25,289 26,274
Deferred income taxes, net (2,802) (785) (4,441)
Deferred investment tax credits, net (487) (528) (535)
Gain on sale of assets (2,142) - (2,763)
Gain on sale of equity securities (2,878) - -
Net change in:
Accounts receivable 1,523 (6,360) (3,615)
Inventories (23,467) 466 438
Accounts payable (129) 4,990 4,405
Other current assets and liabilities 15,798 (1,808) (3,394)
Other, net (2,824) 1,096 (2,695)
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 34,343 40,441 30,302
- ------------------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to property, plant and equipment (45,543) (43,672) (22,533)
Proceeds from sale of assets 8,624 - 10,750
Proceeds from sale of equity securities 4,808 - -
Payments on notes receivable 1,639 1,388 -
Other, net 2,485 819 383
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (27,987) (41,465) (11,400)
- ------------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Payment of dividends on common stock (11,749) (10,750) (10,266)
Issuance of common stock 14,711 3,124 1,501
Reduction of long-term debt and preferred stock of subsidiary (12,470) (21,200) (7,302)
Proceeds from issuance of medium-term notes 49,670 14,555 19,200
Net change in short-term debt (34,000) 20,000 (18,000)
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities 6,162 5,729 (14,867)
- ------------------------------------------------------------------------------------------------------------------------------------
Net change in cash and cash equivalents 12,518 4,705 4,035
Cash and cash equivalents at beginning of period 15,008 10,303 6,268
- ------------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 27,526 $ 15,008 $ 10,303
====================================================================================================================================
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
<PAGE> 11
Notes To Consolidated Financial Statements
Energen Corporation and Subsidiaries
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Energen Corporation (the
Company) is a diversified energy holding company engaged primarily in the
distribution, exploration and production of natural gas, principally in central
and north Alabama. The following is a description of the Company's significant
accounting policies and practices.
A. Principles of Consolidation
The accompanying financial statements include the accounts of Energen
Corporation and its subsidiaries, principally Alabama Gas Corporation
(Alagasco), after elimination of all significant intercompany transactions in
consolidation. Until May 1994, the Company owned a 41 percent interest in
American Combustion Inc. and accounted for that investment under the equity
method. Following the sale of a majority of that interest in the current year,
the Company accounts for its remaining 8 percent investment under the cost
method.
B. Property, Plant and Equipment and Related Depreciation
Property, plant and equipment (principally utility plant) is stated at cost.
The cost of utility plant includes an allowance for funds used during
construction. Maintenance is charged for the cost of normal repairs and the
renewal or replacement of an item of property which is less than a retirement
unit. When property which represents a retirement unit is replaced or removed,
the cost of such property is credited to utility plant and, together with the
cost of removal less salvage, is charged to the accumulated reserve for
depreciation. Depreciation is provided on the straight-line method over the
estimated useful lives of utility property at rates established by the Alabama
Public Service Commission (APSC). Approved depreciation rates averaged
approximately 4.3 percent in 1994 and 1993 and 4.4 percent in 1992.
C. Operating Revenue and Gas Costs
In accordance with industry practice, the Company records natural gas
distribution revenue on a monthly and cycle billing basis. The Company extends
credit to its residential and industrial utility customers which are located
primarily in central and north Alabama. The commodity cost of purchased gas
applicable to gas delivered to customers but not yet billed under the cycle
billing method is deferred as a current asset.
D. Income Taxes
The Company's deferred income taxes reflect the impact of temporary differences
between the tax basis of assets and liabilities and their carrying amounts for
financial reporting purposes and are measured in compliance with enacted tax
laws. Investment tax credits have been deferred and are being amortized over
the lives of the related assets.
E. Oil and Gas Producing Activities
The Company follows the successful efforts method of accounting for costs
incurred in the exploration and development of oil and gas reserves. Lease
acquisition costs are capitalized initially, and unproved properties are
reviewed periodically to determine if there has been impairment of the carrying
value, with any such impairment charged to exploration expense currently.
Exploratory drilling costs are capitalized pending determination of proved
reserves. If proved reserves are not discovered, the exploratory drilling costs
are expensed. Other exploration costs, including geological and geophysical
costs, are expensed as incurred. All development costs are capitalized.
Depreciation, depletion and amortization is determined on a field-by-field
basis using the unit-of-production method based on proved reserves. A provision
for anticipated abandonment and restoration costs at the end of a property's
useful life is made through depreciation expense. The Company's oil and gas
subsidiary periodically enters into futures contracts to hedge its exposure to
price fluctuations on oil and gas production. Gains and losses on futures
contracts are recognized in the income statement as the hedged volumes are
produced.
F. Cash Equivalents
The Company includes highly liquid marketable securities and debt instruments
purchased with a maturity of three months or less in cash equivalents.
<PAGE> 12
2. LONG-TERM DEBT AND NOTES PAYABLE Long-term debt consists of the following:
<TABLE>
<CAPTION>
====================================================================================================================================
As of September 30, (in thousands) 1994 1993
====================================================================================================================================
<S> <C> <C>
Energen Corporation:
8% debentures, due up to $1,000,000 annually to February 1, 2007 $ 19,935 $ 19,960
Series 1993 notes, interest ranging from 4.65% to 7.25%, due annually beginning
March 1, 1996, in payments ranging from $775,000 to $1,675,000 to March 1, 2008 14,976 15,000
Notes payable, interest ranging from 9.3% to 10.05%, scheduled to be repaid in 1995 6,300 7,100
Alabama Gas Corporation:
First Mortgage Bonds, 11% Series H, due $1,500,000 annually to January 15, 1999 7,500 9,000
Medium-term notes, interest ranging from 5.4% to 7.2%, for notes redeemable
December 1, 1998, to December 15, 2023 50,000 -
9% debentures, due up to $1,200,000 annually to November 1, 2014 28,758 28,758
8.75% debentures, redeemed during fiscal year 1994 - 8,299
Mortgage note payable, due $30,800 quarterly to April 1, 2002;
interest is variable 956 1,048
Other Entities:
First Mortgage Note, repaid during fiscal year 1994 - 1,680
Other - 50
- ------------------------------------------------------------------------------------------------------------------------------------
Total 128,425 90,895
Less amounts due within one year 10,123 5,043
- ------------------------------------------------------------------------------------------------------------------------------------
Total $118,302 $ 85,852
====================================================================================================================================
</TABLE>
Substantially all utility plant serves as collateral for the Alabama Gas
Corporation First Mortgage Bonds. Utility plant having a net book value of
$1,703,000 serves as collateral for the mortgage note payable which has a
variable interest rate of 1.47 percent above the 91-day U.S. Treasury Bill
rate, adjusted quarterly. The applicable year-end interest rates were 5.66
percent and 4.54 percent for 1994 and 1993, respectively.
The aggregate maturities of long-term debt for the next five years are as
follows:
<TABLE>
<CAPTION>
====================================================================================================================================
Years ending September 30, (in thousands)
====================================================================================================================================
1995 1996 1997 1998 1999
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
$10,123 $4,598 $4,648 $4,698 $10,073
====================================================================================================================================
</TABLE>
The Company and Alagasco are subject to various restrictions on the payment of
dividends. The most restrictive provisions are: (1) Under Energen's 8 percent
debentures, dividends or other distributions with respect to common stock may
not be made unless the Company maintains a minimum consolidated tangible net
worth of $80 million; at September 30, 1994, Energen had a tangible net worth
of $166,799,000; and, (2) Under Alagasco's 9 percent debentures, utility
dividends or other distributions with respect to utility common stock may not
be made unless the utility maintains a consolidated tangible net worth, as
defined, of at least $50 million. At September 30, 1994, Alagasco had a
tangible net worth of $115,364,000.
The Company and Alagasco have short-term credit lines and other credit
facilities of $110 million available to either entity for working capital
needs.
<PAGE> 13
The following is a summary of information relating to notes payable to banks:
<TABLE>
<CAPTION>
====================================================================================================================================
As of September 30, (in thousands) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Amount outstanding $ 6,000 $ 40,000 $ 20,000
Available for borrowings 104,000 70,000 90,000
- ------------------------------------------------------------------------------------------------------------------------------------
Total $ 110,000 $ 110,000 $ 110,000
====================================================================================================================================
Maximum amount outstanding at any month-end $ 60,000 $ 43,000 $ 43,000
Average daily amount outstanding $ 13,836 $ 31,318 $ 28,642
Weighted average interest rates based on:
Average daily amount outstanding 3.32% 3.42% 4.74%
Amount outstanding at year-end 5.17% 3.33% 3.42%
====================================================================================================================================
</TABLE>
Total interest expense for Energen in 1994, 1993 and 1992 was $11,345,000,
$10,605,000, and $10,476,000 (of which $61,000 was capitalized), respectively.
3. REGULATORY As an Alabama utility, Alagasco is subject to regulation by the
APSC which, in 1983, established the Rate Stabilization and Equalization (RSE)
rate-setting process. RSE was extended for the third time on December 3, 1990,
for a three-year period. Under the terms of that extension, RSE shall continue
after November 30, 1993, unless, after notice to the Company, the Commission
votes to either modify or discontinue its operation. On October 4, 1993, the
Commission unanimously voted to extend RSE until such time as certain hearings
mandated by the Energy Policy Act of 1992 (Energy Act) in connection with
integrated resource planning and demand-side management programs are completed.
The Energy Act proceedings are expected to conclude during fiscal 1995 at which
time it is expected that the Commission will consider renewal of RSE.
Under RSE as extended, the APSC conducts quarterly reviews to determine, based
on Alagasco's projections and fiscal year-to-date performance, whether
Alagasco's return on equity for the fiscal year will be within the allowed
range of 13.15 percent to 13.65 percent. Reductions in rates can be made
quarterly to bring the projected return within the allowed range. Increases,
however, are allowed only once each fiscal year, effective December 1, and
cannot exceed 4 percent of prior-year revenues. RSE limits the utility's equity
upon which a return is permitted to 60 percent of total capitalization and
provides for certain cost control measures designed to monitor the Company's
operations and maintenance (O&M) expense. If O&M expense per customer falls
within 1.25 percentage points above or below the Consumer Price Index For All
Urban Customers (index range), no adjustment is required. If, however, O&M
expense per customer exceeds the index range, three-quarters of the difference
will be returned to the customers. To the extent O&M expense per customer is
less than the index range, the utility will benefit by one-half of the
difference through future rate adjustments. Effective December 15, 1990, the
APSC approved a temperature adjustment to customers' monthly bills to mitigate
the effect of departures from normal temperature on Alagasco's earnings. The
calculation is performed monthly, and adjustments to customer's bills are made
in the same month the weather variation occurs.
The Company's rate schedules for natural gas distribution charges contained a
Purchased Gas Adjustment (PGA) rider in 1993 which permitted the pass-through
of changes in gas costs to customers. The APSC approved, effective October 4,
1993, the replacement of the PGA rider with the new Gas Supply Adjustment rider
in order to accommodate changes in gas supply purchases resulting from
implementation of FERC Order 636, including gas supply realignment surcharges
imposed by the Company's suppliers.
In accordance with APSC-directed regulatory accounting procedures, Alagasco in
1989 began returning excess utility deferred taxes which resulted from a
reduction in the federal statutory tax rate from 46 percent to 34 percent using
the average rate assumption method. This method provides for the return to
ratepayers of excess deferred taxes over the lives of the related assets. In
1993 those excess taxes were reduced as a result of a federal tax rate increase
from 34 percent to 35 percent. Approximately $3.1 million of remaining excess
utility deferred taxes are being returned to ratepayers over approximately 16
years.
<PAGE> 14
4. INCOME TAXES The components of income taxes consist of the following:
<TABLE>
<CAPTION>
====================================================================================================================================
For the years ended September 30, (in thousands) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Taxes estimated to be payable currently:
Federal $ 8,550 $ 3,905 $ 4,836
State 1,369 611 522
- ------------------------------------------------------------------------------------------------------------------------------------
Total current 9,919 4,516 5,358
- ------------------------------------------------------------------------------------------------------------------------------------
Taxes deferred:
Federal (2,976) (1,280) (5,214)
State (332) 172 238
- ------------------------------------------------------------------------------------------------------------------------------------
Total deferred (3,308) (1,108) (4,976)
- ------------------------------------------------------------------------------------------------------------------------------------
Total income tax expense $ 6,611 $ 3,408 $ 382
====================================================================================================================================
</TABLE>
As discussed in Note 14, the Company adopted SFAS 109 as of October 1, 1991,
and the cumulative effect of this change is reported in the 1992 consolidated
statements of income.
Temporary differences and carryforwards which give rise to a significant
portion of deferred tax assets and liabilities for 1994 and 1993 are as
follows:
<TABLE>
<CAPTION>
====================================================================================================================================
As of September 30, (in thousands) 1994 1993
====================================================================================================================================
<S> <C> <C>
Deferred tax assets:
Deferred investment tax credits $ 1,567 $ 1,748
Regulatory liabilities 2,585 2,866
Minimum tax credit 12,469 12,043
Insurance and accruals 1,568 1,010
Unbilled revenue 1,454 1,426
Other, net 6,448 4,797
- ------------------------------------------------------------------------------------------------------------------------------------
Subtotal 26,091 23,890
Valuation allowance - -
- ------------------------------------------------------------------------------------------------------------------------------------
Total deferred tax assets $ 26,091 $ 23,890
====================================================================================================================================
Deferred tax liabilities:
Depreciation and basis differences $ 16,905 $ 16,635
Basis differences on oil and gas producing properties 1,564 1,221
Pension and other benefit costs 1,306 1,222
Other, net 480 1,202
- ------------------------------------------------------------------------------------------------------------------------------------
Total deferred tax liabilities $ 20,255 $ 20,280
====================================================================================================================================
</TABLE>
No valuation allowance with respect to deferred taxes is deemed necessary, as
the Company anticipates generating adequate future taxable income to realize
the benefits of all deferred tax assets on the balance sheet. As of September
30, 1994, the amount of minimum tax credit which can be carried forward
indefinitely to reduce future regular tax liability is $12,469,000.
Total income tax expense differs from the amount which would be provided by
applying the statutory federal income tax rate to pretax earnings as
illustrated below:
<TABLE>
<CAPTION>
====================================================================================================================================
For the years ended September 30, (in thousands) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Income tax expense at statutory federal income tax rate $ 10,627 $ 7,467 $ 5,464
Increase (decrease) resulting from:
Nonconventional fuel credits--current (4,259) (1,374) (1,302)
Nonconventional fuel credits--deferred 127 (2,446) (3,775)
Investment tax credits--deferred (487) (528) (535)
Return of utility excess deferred taxes (76) (172) -
State income taxes, net of federal income tax benefit 700 639 609
Other, net (21) (178) (79)
- ------------------------------------------------------------------------------------------------------------------------------------
Total income tax expense $ 6,611 $ 3,408 $ 382
====================================================================================================================================
</TABLE>
<PAGE> 15
5. RETIREMENT INCOME PLANS AND OTHER BENEFITS The Company has two defined
benefit non-contributory pension plans which cover a majority of employees.
Benefits are based on years of service and final earnings. The Company's policy
is to use the "projected unit credit" actuarial method for funding and
financial reporting purposes. The expense (income) for the plan covering the
majority of employees for the years ended September 30, 1994, 1993 and 1992,
was $15,000, $(118,000), and $(278,000), respectively. The expense for the
second plan covering employees under labor union agreements for 1994, 1993 and
1992 was $555,000, $557,000, and $503,000, respectively.
The funded status of the plans is as follows:
<TABLE>
<CAPTION>
====================================================================================================================================
Assets Exceed Accumulated Benefits
As of June 30, (in thousands) Accumulated Benefits Exceed Assets
====================================================================================================================================
1994 1993 1994 1993
------------------------ ------------------------
<S> <C> <C> <C> <C>
Vested benefits $(48,354) $ (46,513) $(12,860) $(12,258)
Nonvested benefits (5,530) (5,403) (2,253) (2,121)
- ------------------------------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation (53,884) (51,916) (15,113) (14,379)
Effects of salary progression (10,332) (9,803) - -
- ------------------------------------------------------------------------------------------------------------------------------------
Projected benefit obligation (64,216) (61,719) (15,113) (14,379)
Fair value of plan assets, primarily equity and fixed income
securities 72,004 73,576 11,863 11,815
Unrecognized net gain 2,646 (434) 1,034 124
Unrecognized prior service cost 46 51 1,554 1,696
Unrecognized net transition obligation (asset) (6,524) (7,332) 452 509
Additional minimum liability - - (3,040) (2,329)
- ------------------------------------------------------------------------------------------------------------------------------------
Accrued pension asset (liability) $ 3,956 $ 4,142 $ (3,250) $ (2,564)
====================================================================================================================================
</TABLE>
At September 30, 1994 and 1993, the discount rate used to measure the projected
benefit obligation was 7.5 percent for both plans, and the annual rate of
salary increase for the salaried plan was 5.5 percent. The expected long-term
rate of return on plan assets was 8.25 percent for both plans in 1994 and 8
percent in 1993.
The components of net pension costs for 1994, 1993 and 1992 were:
<TABLE>
<CAPTION>
====================================================================================================================================
Assets Exceed Accumulated Benefits
For the years ended September 30, (in thousands) Accumulated Benefits Exceed Assets
====================================================================================================================================
1994 1993 1992 1994 1993 1992
---------------------------- --------------------------
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 1,873 $ 1,678 $ 1,560 $ 224 $ 187 $ 176
Interest cost on projected benefit obligation 4,550 4,097 3,807 1,042 1,018 970
Actual return on plan assets (504) (6,858) (6,123) (372) (1,048) (1,116)
Net amortization and deferral (5,904) 965 478 (339) 400 473
- ------------------------------------------------------------------------------------------------------------------------------------
Net pension (income) expense $ 15 $ (118) $ (278) $ 555 $ 557 $ 503
====================================================================================================================================
</TABLE>
The Company has deferred compensation plan agreements for certain key
executives providing for payments on retirement, death or disability. The
deferred compensation expense under these agreements for 1994, 1993 and 1992
was $461,000, $650,000, and $528,000, respectively.
In addition to providing pension benefits, the Company provides certain
post-employment health care and life insurance benefits. Substantially all of
the Company's employees may become eligible for such benefits if they reach
normal retirement age while working for the Company. In a prior year, the
Company adopted SFAS No. 106, Employers' Accounting for Post-retirement
Benefits Other Than Pensions, with respect to the accrual of such costs for
salaried employees. During fiscal year 1994, the Company adopted SFAS 106 with
respect to such costs for employees under collective bargaining agreements.
There is no cumulative effect on the income statement resulting from the
adoption of SFAS 106, as the Company elected to amortize transition costs over
a 20-year period. On December 6, 1993, the APSC adopted Order 4-3454 which
allows the Company to recover all costs accrued under SFAS 106 through rates.
While the Company has not adopted a formal funding policy, all of its accrued
post-retirement liability was funded at year-end.
<PAGE> 16
The expense for salaried employees for the years ended September 30, 1994,
1993, and 1992 was $2,319,000, $2,677,000, and $2,439,000, respectively. Prior
to 1994, the Company recognized the cost of providing post-retirement benefits
for union employees on a "pay-as-you-go" basis. These benefits were provided
through a self-insurance arrangement and through insurance companies whose
premiums were based on the benefits paid during the year. In 1994 the expense
for union employees was $3,685,000, an increase of $2,246,000 over what would
have been recognized under the "pay-as-you-go" method. Expense of $982,000 and
$882,000 was incurred during 1993 and 1992, respectively. The "projected unit
credit" actuarial method was used to determine the normal cost and actuarial
liability.
A reconciliation of the estimated status of the obligation is as follows:
<TABLE>
<CAPTION>
====================================================================================================================================
As of June 30, (in thousands) Salaried Employees Union Employees
====================================================================================================================================
1994 1993 1994 1993
------------------------- ---------------------------
<S> <C> <C> <C> <C>
Accumulated post-employment benefit obligation $ (21,296) $(23,067) $(24,564) $ -
Plan assets 9,408 6,488 1,248 -
Unamortized amounts 11,751 14,456 21,357 -
- ------------------------------------------------------------------------------------------------------------------------------------
Accrued post-employment benefit liability $ (137) $ (2,123) $ (1,959) $ -
====================================================================================================================================
</TABLE>
Net periodic post-employment benefit cost for the years ended September 30,
1994, 1993, and 1992, included the following:
<TABLE>
<CAPTION>
====================================================================================================================================
For the years ended September 30, (in thousands) Salaried Employees Union Employees
====================================================================================================================================
1994 1993 1992 1994 1993 1992
------------------------------ ------------------------------
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 450 $ 464 $ 321 $ 481 $ - $ -
Interest cost on accumulated post-employment
benefit obligation 1,726 1,457 1,276 1,920 - -
Amortization of transition obligation 723 842 842 1,285 - -
Amortization of actuarial gains and losses - 49 - - - -
Deferred asset (gain) loss (453) - - - - -
Actual return on plan assets (127) (135) - (1) - -
- ------------------------------------------------------------------------------------------------------------------------------------
Net periodic post-employment benefit expense $ 2,319 $ 2,677 $ 2,439 $ 3,685 $ - $ -
====================================================================================================================================
</TABLE>
The weighted average health care cost trend rate used in determining the
accumulated post-employment benefit obligation was 8 percent in 1994 and 1993
and 8.5 percent in 1992. That assumption has a significant effect on the
amounts reported. For example, with respect to salaried employees, increasing
the weighted average health care cost trend rate by 1 percent would increase
the accumulated post-employment benefit obligation by 3.8 percent and the net
periodic post-employment benefit cost by 4.7 percent. For union employees,
increasing the weighted average health care cost trend rate by 1 percent would
increase the accumulated post-employment benefit obligation by 5.8 percent and
the net periodic post-employment benefit cost by 5.4 percent. The weighted
average discount rate used in determining the accumulated post-employment
benefit obligation was 7.5 percent in 1994 and 1993 and 8 percent in 1992.
The Company has a long-term disability plan covering most salaried employees.
Expense for the years ended September 30, 1994, 1993, and 1992, was $150,000,
$129,000, and $129,000, respectively.
6. COMMON STOCK PLANS A majority of Company employees are eligible to
participate in the Energen Employee Savings Plan (ESP) by investing a portion
of their compensation in the Plan, with the Company matching a part of the
employee investment by contributing Company common stock. The ESP also contains
employee stock ownership plan provisions. The Company issued 36,355 common
shares to the ESP in 1994, 111,895 shares in 1993, and 76,203 shares in 1992.
At September 30, 1994, 481,484 common shares were reserved for issuance under
the ESP. Expense associated with Company contributions to the ESP was
$2,772,000, $2,601,000, and $2,431,000 for 1994, 1993 and 1992, respectively.
The Restricted Stock Incentive Plan of Energen Corporation, adopted in 1984,
provided for the award of common stock to eligible participants. Stock awarded
under the Plan is subject to certain restrictions against sale or pledge.
Pursuant to its terms, the Plan terminated effective January 1994 subject to
completion of restriction periods applicable to previously awarded shares.
Under the Plan, no common shares were awarded in 1994, 1993, or 1992. Expense
of $218,000, $289,000 and $303,000 was charged during 1994, 1993 and 1992,
respectively, under this Plan.
<PAGE> 17
The Company has a dividend reinvestment plan for which 161,437 common shares
were reserved at September 30, 1994.
The Energen Corporation 1988 Stock Option Plan provides for the grant of
incentive stock options, non-qualified stock options, or a combination thereof
to officers and key employees. Options granted under the Plan provide for
purchase of the Company's common stock at not less than the fair market value
on the date the option is granted. Under the Plan, 270,000 shares of the
Company's common stock have been reserved for issuance. Options were granted in
1993 and 1991 with dividend equivalents, 1,900 of which have been exercised,
and, in 1990, with stock appreciation rights (SARS), 12,696 of which were
canceled upon exercise.
Transactions under the Plan are summarized as follows:
<TABLE>
<CAPTION>
====================================================================================================================================
As of September 30, 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Outstanding at beginning of year ($16.75 - $20.125) 141,556 111,152 130,986
Granted (at $16.75 - $18.375) - 45,000 -
Exercised ($22.875 - $25.125) - (1,900) -
Canceled upon exercise of Stock Appreciation Rights ($23.25 - $26.375) - (12,696) -
Forfeited - - (19,834)
- ------------------------------------------------------------------------------------------------------------------------------------
Outstanding at year-end 141,556 141,556 111,152
- ------------------------------------------------------------------------------------------------------------------------------------
Exercisable at year-end 141,556 141,556 111,152
- ------------------------------------------------------------------------------------------------------------------------------------
Remaining reserved for issuance at year-end 113,848 113,848 158,848
====================================================================================================================================
</TABLE>
In 1992 the Company adopted the Energen Corporation 1992 Long-Range Performance
Plan which provides for the award of up to 500,000 performance units, with each
unit equal to the market value of one share of common stock, to eligible
employees based on predetermined performance criteria at the end of a four-year
award period. Under the Plan, a portion of the performance units is payable
with Company common stock; accordingly, 350,000 shares have been reserved for
issuance. Under the Plan, 49,120, 59,850 and 53,774 performance units were
awarded in 1994, 1993 and 1992, respectively, leaving 337,256 performance units
available for award at September 30, 1994. The Company recorded expense of
$939,000, $688,000 and $175,000 for 1994, 1993 and 1992, respectively, under
the Plan.
In 1992 the Company adopted the Energen Corporation 1992 Directors Stock Plan
to enable the Company to pay part of the compensation of its non-employee
directors in shares of the Company's common stock. Under the Plan, 3,515 and
5,085 shares were issued in 1994 and 1993, respectively, leaving 93,423 shares
reserved for issuance at September 30, 1994.
The Company has adopted a Shareholder Rights Plan intended to protect
shareholders from coercive or unfair takeover tactics. Under certain
circumstances, shareholders have the right to acquire the Company's Series A
Junior Participating Preferred Stock (or, in certain cases, securities of an
acquiring person) at a significant discount. Terms and conditions are set forth
in a Rights Agreement (dated July 27, 1988, and amended February 28, 1990)
between the Company and its Rights Agent. In general, in the absence of certain
takeover-related events, as described in the Plan, the rights may be redeemed
prior to their July 27, 1998, expiration for $0.02 per right.
7. PREFERRED STOCK The Company is authorized to issue 5,000,000 shares of
cumulative preferred stock, par value $0.01 per share, in one or more series,
150,000 of which have been designated as Series A Junior Participating
Preferred Stock. None of these shares are issued or outstanding.
Alagasco is authorized to issue 120,000 shares of preferred stock, par value
$0.01 per share, in one or more series. Alagasco's $4.70 Series cumulative
preferred stock had an annual sinking fund requirement to redeem 2,000 shares
of such stock at par plus accrued dividends to date of redemption. On July 30,
1993, all outstanding shares of Alagasco's $4.70 Series cumulative preferred
stock were redeemed.
8. COMMITMENTS The Company has various firm gas supply and firm gas
transportation contracts, which expire at various dates through the year
2008. These contracts typically contain minimum demand charge obligations on
the part of the Company.
<PAGE> 18
In January 1989, the Company entered into an agreement with a financial
institution whereby it can sell on an ongoing basis, with recourse, certain
installment receivables related to its merchandising program up to a maximum of
$15 million. During 1994 and 1993, the Company sold $6,784,000 and $5,608,000,
respectively, of installment receivables. At September 30, 1994 and 1993, the
balance of these installment receivables was $13,027,000 and $11,699,000,
respectively. Receivables sold under this agreement are considered financial
instruments with off-balance sheet risk. The Company's exposure to credit loss
in the event of non-performance by customers is represented by the balance of
installment receivables.
The Company's oil and gas subsidiary periodically enters into futures contracts
to hedge its exposure to price fluctuations on oil and gas production. Under
this program, Taurus has entered into futures contracts for the sale of 5 Bcf
of its fiscal 1995 gas production at an average contract price of $2.17 and for
the sale of 160,000 barrels of its oil production at an average contract price
of $18.61.
9. LEASES Total payments related to leases included as operating expense in
the accompanying consolidated statements of income were $2,986,000,
$3,228,000, and $4,358,000 in 1994, 1993 and 1992, respectively. Minimum future
rental payments (in thousands) required after 1994 under leases with initial or
remaining noncancelable lease terms in excess of one year are as follows:
<TABLE>
<CAPTION>
====================================================================================================================================
1995 1996 1997 1998 1999 2000 and thereafter
====================================================================================================================================
<S> <C> <C> <C> <C> <C>
$2,130 $2,021 $574 $97 $91 $173
====================================================================================================================================
</TABLE>
10. ENVIRONMENTAL MATTERS Alagasco is in the chain of title of eight former
manufactured gas plant sites, of which it still owns four, and five
manufactured gas distribution sites, of which it still owns one. A preliminary
investigation of the sites does not indicate the present need for remediation
activities. Management expects that, should remediation of any such sites be
required in the future, Alagasco's share, if any, of such costs will not
materially affect the results of operations or financial condition of Alagasco.
Taurus is subject to various environmental regulations. Management believes
that Taurus is in compliance with the currently applicable standards of the
environmental agencies to which it is subject and that potential environmental
liabilities, if any, are minimal. Also, to the extent Taurus has operating
agreements with various joint venture partners, environmental costs, if any,
would be shared proportionately.
11. SUPPLEMENTAL CASH FLOW INFORMATION Supplemental information concerning
cash flow activities is as follows:
<TABLE>
<CAPTION>
====================================================================================================================================
For the years ended September 30, (in thousands) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Interest paid, net of amount capitalized $ 11,055 $ 11,906 $ 11,634
Income taxes paid $ 10,965 $ 5,133 $ 6,285
Noncash investing activities:
Notes receivable--sale of properties $ - $ - $ 7,100
Capitalized depreciation $ 155 $ 187 $ 175
Allowance for funds used during construction $ 465 $ 163 $ 50
Noncash financing activities (debt issuance costs) $ 330 $ 445 $ 800
====================================================================================================================================
</TABLE>
12. SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED) The following data
summarize quarterly operating results. The Company's business is seasonal in
character and strongly influenced by weather conditions.
<TABLE>
<CAPTION>
====================================================================================================================================
1994 Fiscal Quarters
(In thousands, except per share amounts) First Second Third Fourth
====================================================================================================================================
<S> <C> <C> <C> <C>
Operating revenues $ 87,919 $ 168,087 $ 73,125 $ 47,942
Operating income (loss) $ 5,713 $ 30,370 $ 4,325 $ (4,500)
Net income (loss) $ 2,300 $ 22,192 $ 3,950 $ (4,691)
Earnings (loss) per average common share $ 0.22 $ 2.03 $ 0.36 $ (0.43)
====================================================================================================================================
</TABLE>
<PAGE> 19
<TABLE>
<CAPTION>
1993 Fiscal Quarters
(In thousands, except per share amounts) First Second Third Fourth
====================================================================================================================================
<S> <C> <C> <C> <C>
Operating revenues $ 84,108 $ 149,646 $ 75,324 $ 48,038
Operating income (loss) $ 5,366 $ 26,867 $ 2,981 $ (4,947)
Net income (loss) $ 2,670 $ 19,945 $ 1,081 $ (5,615)
Earnings (loss) per average common share $ 0.26 $ 1.95 $ 0.11 $ (0.55)
====================================================================================================================================
</TABLE>
13. INDUSTRY SEGMENT INFORMATION The Company is principally engaged in the
purchase, distribution and sale of natural gas in central and north Alabama and
the development of oil and gas in the continental United States. The Company
also is engaged in intrastate gas transmission services and merchandising.
<TABLE>
<CAPTION>
====================================================================================================================================
As of September 30, (in thousands) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Operating revenues, unaffiliated customers:
Natural gas distribution $ 344,637 $ 330,560 $ 310,726
Oil and gas production 22,294 16,463 11,280
Other 10,142 10,093 9,976
- ------------------------------------------------------------------------------------------------------------------------------------
Total $ 377,073 $ 357,116 $ 331,982
====================================================================================================================================
Intersegment revenues:
Natural gas distribution $ - $ - $ -
Oil and gas production 2,917 3,424 4,438
Other 5,259 4,833 5,123
- ------------------------------------------------------------------------------------------------------------------------------------
Total $ 8,176 $ 8,257 $ 9,561
====================================================================================================================================
Depreciation, depletion and amortization expense:
Natural gas distribution $ 17,941 $ 17,206 $ 17,154
Oil and gas production 9,065 6,947 7,957
Other 994 1,136 1,163
- ------------------------------------------------------------------------------------------------------------------------------------
Total $ 28,000 $ 25,289 $ 26,274
====================================================================================================================================
Capital expenditures:
Natural gas distribution $ 38,473 $ 22,107 $ 20,228
Oil and gas production 7,356 21,449 1,838
Other 334 480 692
- ------------------------------------------------------------------------------------------------------------------------------------
Total $ 46,163 $ 44,036 $ 22,758
====================================================================================================================================
Identifiable assets (year-end):
Natural gas distribution $ 308,905 $ 264,548 $ 258,902
Oil and gas production 92,019 84,664 60,839
Other 10,390 21,473 22,378
- ------------------------------------------------------------------------------------------------------------------------------------
Total $ 411,314 $ 370,685 $ 342,119
====================================================================================================================================
Operating income (loss) before income taxes:
Natural gas distribution $ 30,017 $ 26,381 $ 25,915
Oil and gas production 5,701 4,539 (4,181)
Other 1,594 929 2,009
Eliminations and corporate expenses (1,404) (1,582) (950)
- ------------------------------------------------------------------------------------------------------------------------------------
Total 35,908 30,267 22,793
Interest expense (11,345) (10,605) (10,415)
Dividends on preferred stock of subsidiary - (70) (85)
Gain on sale of assets 2,142 - 2,763
Other, net 3,657 1,897 1,013
- ------------------------------------------------------------------------------------------------------------------------------------
Income before income taxes $ 30,362 $ 21,489 $ 16,069
====================================================================================================================================
</TABLE>
<PAGE> 20
14. ACCOUNTING CHANGE As discussed more fully in Note 5, the Company adopted
SFAS 106, Employers' Accounting for Postretirement Benefits Other Than
Pensions, with respect to the accrual of such costs for all employees under
labor union agreements effective October 1, 1993. The Company adopted SFAS 106
with respect to salaried employees in a prior year.
Effective October 1, 1991, the Company elected early adoption of SFAS 109,
Accounting for Income Taxes, which was required to be adopted by the Company no
later than its fiscal year ending September 30, 1994. In 1992 this adoption
resulted in additional income before the effect of the change of $438,000, or
$0.04 per share, and income from the cumulative effect of the change in
accounting principle of $941,000, or $.10 per share. The cumulative effect on
the income statement of the adoption of SFAS 109 relates to the Company's
non-regulated subsidiaries. Changes in the utility's deferred income taxes
arising from the adoption represent income taxes returnable through future
rates over the life of the related assets and have been recorded as a
regulatory liability on the balance sheets.
15. OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) The following schedules
detail historical financial data of the Company's oil and gas producing
activities. Certain terms appearing in the schedules are prescribed by the
Securities and
<PAGE> 21
Exchange Commission and are briefly described as follows:
* Lease Acquisition Costs are costs incurred to lease or otherwise acquire a
property.
* Exploration Expenses are primarily costs associated with drilling
unsuccessful exploratory wells in undeveloped properties, exploratory
geological and geophysical activities, and costs of impaired leaseholds.
* Development Costs include costs necessary to gain access to, prepare and
equip development wells in areas of proved reserves.
* Production (Lifting) Costs include costs incurred to operate and maintain
wells.
* Gross Revenues are reported after deduction of royalty interest payments.
* Gross Well or Acre is a well or acre in which a working interest is owned.
* Net Well or Acre is deemed to exist when the sum of fractional ownership
working interests in gross wells or acres equals one.
* Dry Well is an exploratory or a development well found to be incapable of
producing either oil or gas in sufficient quantities to justify completion as
an oil or gas well.
* Productive Well is an exploratory or a development well that is not a dry
well.
CAPITALIZED COSTS
<TABLE>
<CAPTION>
====================================================================================================================================
As of September 30, (in thousands) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Proved $ 90,709 $ 84,373 $ 64,340
Unproved 1,646 1,704 1,282
- ------------------------------------------------------------------------------------------------------------------------------------
Total capitalized costs 92,355 86,077 65,622
Accumulated depreciation, depletion and amortization 43,052 35,150 29,485
- ------------------------------------------------------------------------------------------------------------------------------------
Capitalized costs, net $ 49,303 $ 50,927 $ 36,137
====================================================================================================================================
</TABLE>
<PAGE> 22
COSTS INCURRED The following table sets forth costs incurred in property
acquisition and exploration and development activities and includes both
capitalized costs and costs charged to expense during the year:
<TABLE>
<CAPTION>
====================================================================================================================================
As of September 30, (in thousands) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Property acquisition:
Proved $ 1,372 $ 11,645 $ -
Unproved 1,169 154 1,391
Exploration 4,565 3,336 1,585
Development 1,438 6,673 1,010
- ------------------------------------------------------------------------------------------------------------------------------------
Total costs incurred $ 8,544 $ 21,808 $ 3,986
====================================================================================================================================
</TABLE>
RESULTS OF OPERATIONS The following table sets forth results of the Company's
oil and gas producing activities:
<TABLE>
<CAPTION>
====================================================================================================================================
Years ended September 30, (in thousands) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Gross revenues:
Unaffiliated (excluding consulting revenues) $ 21,577 $ 14,974 $ 10,537
Affiliated 2,917 3,424 4,438
Production (lifting) costs 5,882 5,383 5,201
Exploration expense 2,088 756 2,588
Depreciation, depletion and amortization 8,080 5,852 6,157
Income taxes (1,607) (1,185) (4,681)
- ------------------------------------------------------------------------------------------------------------------------------------
Results of operations from producing activities $ 10,051 $ 7,592 $ 5,710
====================================================================================================================================
</TABLE>
AVERAGE SALES PRICE, PRODUCTION COST AND DEPRECIATION RATE
<TABLE>
<CAPTION>
====================================================================================================================================
Years ended September 30, 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Average sales price:
Gas (per Mcf) $ 1.89 $ 1.83 $ 1.62
Oil (per barrel) $ 14.25 $ 17.09 $ 17.65
Average production (lifting) cost (per Mcf equivalent) $ 0.57 $ 0.72 $ 0.71
Average depreciation rate (per Mcf equivalent) $ 0.78 $ 0.78 $ 0.84
====================================================================================================================================
</TABLE>
Drilling Activity The following table sets forth the total number of net
productive and dry exploratory and development wells drilled:
<TABLE>
<CAPTION>
====================================================================================================================================
Years ended September 30, 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Exploratory:
Productive 0.6 0.9 0.7
Dry 0.4 0.3 0.2
- ------------------------------------------------------------------------------------------------------------------------------------
Total 1.00 1.2 0.9
====================================================================================================================================
Development:
Productive 0.7 3.7 1.3
Dry -- -- 0.1
- ------------------------------------------------------------------------------------------------------------------------------------
Total 0.7 3.7 1.4
====================================================================================================================================
</TABLE>
As of September 30, 1994, the Company was participating in the drilling of 5
gross wells, with the Company's interest equivalent to .74 wells.
<PAGE> 23
PRODUCTIVE WELLS AND ACREAGE The following table sets forth the total gross
and net productive gas and oil wells and developed and undeveloped acreage:
<TABLE>
<CAPTION>
====================================================================================================================================
As of September 30, 1994 Gross Net
====================================================================================================================================
<S> <C> <C>
Gas Wells 808 208.9
Oil Wells 1,698 22.7
Developed Acreage 239,542 47,510
Undeveloped Acreage 74,873 7,130
====================================================================================================================================
</TABLE>
The Company also had a revenue interest only in an additional 216 gross wells.
There were 25 gross wells with multiple completions with the Company's interest
being an equivalent of 3.0 wells. All wells and acreage are located in the
United States, with the majority of the net undeveloped acreage located in the
Gulf Coast region.
OIL AND GAS PRODUCING ACTIVITIES Taurus's proved reserves are located in the
United States and are as follows:
<TABLE>
<CAPTION>
====================================================================================================================================
Years ended September 30, 1994 1993 1992
====================================================================================================================================
Gas Oil Gas Oil Gas Oil
MMcf MBbl MMcf MBbl MMcf MBbl
--------------- -------------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves at beginning of year 67,298 1,289 51,329 338 73,279 402
Revisions of previous estimates (3,579) 144 400 (13) (3,954) 81
Purchase (sale) of minerals in place 456 201 11,467 1,149 (18,971) -
Discoveries and other additions 5,051 42 10,347 19 7,390 -
Production (9,169) (191) (6,245) (204) (6,415) (145)
- ------------------------------------------------------------------------------------------------------------------------------------
Proved reserves at end of year 60,057 1,485 67,298 1,289 51,329 338
====================================================================================================================================
</TABLE>
During 1993, Taurus purchased working interests in conventional oil and gas
properties primarily funded by the 1992 property sale in which Taurus sold a
portion of its coalbed methane properties for cash of $10.8 million and a note
of $7.1 million. The sale resulted in a one-time net gain in 1992 of $1.8
million.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES The standardized measure of discounted future net cash flows
is not intended, nor should it be interpreted, to present the fair market value
of the Company's crude oil and natural gas reserves. An estimate of fair market
value would take into consideration factors such as, but not limited to, the
recovery of reserves not presently classified as proved reserves, anticipated
future changes in prices and costs, and a discount factor more representative
of the time value of money and the risks inherent in reserve estimates.
<TABLE>
<CAPTION>
====================================================================================================================================
Years ended September 30, (in thousands) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Future gross revenues $105,986 $ 164,483 $ 97,654
Future production and development costs 54,137 62,185 39,447
- ------------------------------------------------------------------------------------------------------------------------------------
Future net cash flows before income taxes 51,849 102,298 58,207
Future income tax expense (benefit) including tax credits (15,856) 1,304 (12,757)
- ------------------------------------------------------------------------------------------------------------------------------------
Future net cash flows after income taxes 67,705 100,994 70,964
Discount at 10% per annum 16,051 28,210 22,666
- ------------------------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows relating to
proved oil and gas reserves $ 51,654 $ 72,784 $ 48,298
====================================================================================================================================
</TABLE>
<PAGE> 24
The following are the principal sources of changes in the standardized measure
of discounted future net cash flows:
<TABLE>
<CAPTION>
====================================================================================================================================
Years ended September 30, (in thousands) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Balance at beginning of year $ 72,784 $ 48,298 $ 38,488
- ------------------------------------------------------------------------------------------------------------------------------------
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs (24,969) 5,789 12,379
Net changes due to revisions in quantity estimates (2,278) 1,303 (3,726)
Development costs incurred, previously estimated 1,723 1,700 54
Accretion of discount 7,278 4,830 3,849
Other (560) (2,638) (1,820)
- ------------------------------------------------------------------------------------------------------------------------------------
Total Revisions (18,806) 10,984 10,736
New field discoveries and extensions, net of future production
and development costs 523 11,906 5,876
Sales of oil and gas produced, net of production costs (14,635) (9,550) (7,722)
Purchases (sales) of minerals in place 1,354 17,158 (10,499)
Net change in income taxes 10,434 (6,012) 11,419
- ------------------------------------------------------------------------------------------------------------------------------------
Net change in standardized measure of discounted future net cash flows (21,130) 24,486 9,810
- ------------------------------------------------------------------------------------------------------------------------------------
Balance at end of year $ 51,654 $ 72,784 $ 48,298
====================================================================================================================================
</TABLE>
COALBED METHANE ACTIVITIES The Company is actively engaged in the development
of pipeline-quality natural gas from coal (coalbed methane). The results of the
Company's coalbed methane activities have been included in the oil and gas
disclosures shown previously. Because of the significance of coalbed methane to
the Company, certain data are separately disclosed below.
Production of coalbed methane from wells drilled prior to January 1, 1993,
qualifies through December 31, 2002, for federal income tax credits under
Section 29 of the Internal Revenue Code of 1986, as amended. The tax credit
currently approximates 98 cents per Mcf of qualifying production. Accordingly,
a significant portion of the value of proved coalbed methane reserves is
associated with this tax credit.
<TABLE>
<CAPTION>
====================================================================================================================================
Years ended September 30, (MMcf) 1994 1993 1992
====================================================================================================================================
<S> <C> <C> <C>
Proved reserves at beginning of year 34,109 34,306 61,314
Revisions of previous estimates (3,687) 364 (3,612)
Sales of mineral in place - - (18,971)
Discoveries and other additions - 3,231 1,029
Production (3,710) (3,792) (5,454)
- ------------------------------------------------------------------------------------------------------------------------------------
Proved reserves at end of year 26,712 34,109 34,306
====================================================================================================================================
Estimated proved reserves qualifying for tax credits 18,947 21,461 24,543
====================================================================================================================================
Net capitalized costs (in thousands) $21,924 $ 24,896 $ 27,052
====================================================================================================================================
Gross wells in which Taurus has working and/or revenue interest 657 727 677
====================================================================================================================================
Net productive wells 164.2 173.2 165.8
====================================================================================================================================
</TABLE>
16. FINANCIAL INSTRUMENTS In accordance with the requirements of SFAS No.
107, the estimated fair values of the Company's financial instruments at
September 30, 1994, were as follows:
<TABLE>
<CAPTION>
====================================================================================================================================
Carrying Fair
As of September 30, 1994 (in thousands) Amount Value
====================================================================================================================================
<S> <C> <C>
Cash and cash equivalents $ 27,526 $ 27,526
Receivables, net of allowance account $ 34,145 $ 34,145
Short-term debt $ 6,000 $ 6,000
Long-term debt (including current portion) $ 128,425 $ 119,614
====================================================================================================================================
</TABLE>
<PAGE> 25
The following methods and assumptions were used to estimate the fair value of
financial instruments:
* Cash and cash equivalents: Fair value was considered to be the same as the
carrying amount.
* Receivables: The Company believes that, in the aggregate, current and
non-current net receivables were not materially different from the fair value
of those receivables.
* Short-term debt: The fair value was determined to be the same as the
carrying amount.
* Long-term debt: The fair value of fixed-rate long-term debt was based on the
market value of debt with similar maturities and with interest rates currently
trading in the marketplace; the carrying amount of variable rate long-term
debt was assumed to approximate fair value.
<TABLE>
<CAPTION>
====================================================================================================================================
QUARTERLY MARKET PRICES AND DIVIDENDS PAID PER SHARE
====================================================================================================================================
Dividends
Quarter ended (in dollars) High Low Close Paid
====================================================================================================================================
<S> <C> <C> <C> <C>
December 31, 1992 19-1/4 17-5/8 18-3/8 .26
March 31, 1993 23-5/8 18-1/8 22-7/8 .26
June 30, 1993 26-1/2 21-1/4 26 .26
September 30, 1993 26-3/4 23-1/4 24-3/4 .27
December 31, 1993 26-5/8 20-1/8 21-1/2 .27
March 31, 1994 23-7/8 20-1/4 20-1/2 .27
June 30, 1994 23-1/4 19-1/4 20-7/8 .27
September 30, 1994 23-1/2 20-3/4 22-1/2 .28
====================================================================================================================================
</TABLE>
<PAGE> 26
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING
The accompanying consolidated financial statements and related notes of Energen
Corporation were prepared by management, which has the primary responsibility
for the integrity of the financial information therein. The statements were
prepared in conformity with generally accepted accounting principles
appropriate in the circumstances and include amounts which are necessarily
based on management's best estimates and judgments. Financial information
presented elsewhere in this report is consistent with that in the financial
statements.
Management maintains a comprehensive system of internal accounting controls and
relies on the system to discharge its responsibility for the integrity of the
financial statements. This system provides reasonable assurance that corporate
assets are safeguarded and that transactions are recorded in such a manner as
to permit the preparation of reliable financial information. Reasonable
assurance recognizes that the cost of a system of internal accounting controls
should not exceed the related benefits. This system of internal accounting
controls is augmented by written policies and procedures, internal auditing,
and the careful selection and training of qualified personnel. As of September
30, 1994, management was aware of no material weaknesses in Energen's system of
internal accounting controls.
The consolidated financial statements have been audited by the Company's
independent certified public accountants, whose opinion is expressed elsewhere
on this page. Their audit was conducted in accordance with generally accepted
auditing standards; and, in connection therewith, they obtained an
understanding of the Company's system of internal accounting controls and
conducted such tests and related procedures as they deemed necessary to arrive
at an opinion on the fairness of presentation of the consolidated financial
statements.
The functioning of the accounting system and related internal accounting
controls is under the general oversight of the Audit Committee of the Board of
Directors, which is comprised of four outside Directors. The Audit Committee
meets regularly with the independent public accountants and representatives of
management to discuss matters regarding internal accounting controls, auditing
and financial reporting.
Geoffrey C. Ketcham
Executive Vice President,
Chief Financial Officer and Treasurer
James T. McManus
Vice President--Finance and Corporate Development
<PAGE> 27
REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
To the Shareholders of Energen:
We have audited the accompanying consolidated balance sheets of Energen
Corporation and Subsidiaries as of September 30, 1994 and 1993, and the related
consolidated statements of income, shareholders' equity and cash flows for each
of the three years in the period ended September 30, 1994. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Energen
Corporation and Subsidiaries as of September 30, 1994 and 1993, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended September 30, 1994, in conformity with
generally accepted accounting principles.
As discussed in Note 14 to the consolidated financial statements, the Company
changed its method of accounting for certain other postretirement benefits,
effective October 1, 1993, and income taxes effective October 1, 1991.
Coopers & Lybrand L.L.P.
Birmingham, Alabama
October 26, 1994
<PAGE> 28
Selected Financial Data
Energen Corporation and Subsidiaries
<TABLE>
<CAPTION>
====================================================================================================================================
Years ended September 30,
(dollars in thousands, except per share amounts) 1994 1993 1992 1991
====================================================================================================================================
<S> <C> <C> <C> <C>
INCOME STATEMENT
Operating revenues $ 377,073 $ 357,116 $ 331,982 $ 325,643
Income before cumulative effect of change
in accounting principle $ 23,751 $ 18,081 $ 15,687 $ 14,112
Net income $ 23,751 $ 18,081 $ 16,628 $ 14,112
Earnings per share before cumulative effect $ 2.19 $ 1.77 $ 1.54 $ 1.42
Earnings per average common share $ 2.19 $ 1.77 $ 1.64 $ 1.42
====================================================================================================================================
BALANCE SHEET
Capitalization at year-end:
Common shareholders' equity $ 167,026 $ 140,313 $ 129,858 $ 121,995
Preferred stock - - 1,800 1,800
Long-term debt 118,302 85,852 90,609 77,677
- ------------------------------------------------------------------------------------------------------------------------------------
Total capitalization $ 285,328 $ 226,165 $ 222,267 $ 201,472
- ------------------------------------------------------------------------------------------------------------------------------------
Total assets $ 411,314 $ 370,685 $ 342,119 $ 337,516
- ------------------------------------------------------------------------------------------------------------------------------------
Property, plant and equipment, net $ 287,182 $ 273,097 $ 254,630 $ 273,539
====================================================================================================================================
COMMON STOCK DATA
Annual dividend rate at year-end $ 1.12 $ 1.08 $ 1.04 $ 1.00
Cash dividends paid per common share $ 1.09 $ 1.05 $ 1.01 $ .955
Book value per common share $ 15.30 $ 13.60 $ 12.75 $ 12.07
Market-to-book ratio at year-end (%) 147 182 142 150
Yield at year-end (%) 5.0 4.4 5.7 5.5
Return on average common equity (%) 14.6 13.0 13.0 11.6
Price-to-earnings ratio at year-end 10.3 14.0 11.1 12.8
Shares outstanding at year-end (000) 10,918 10,320 10,183 10,104
Price Range:
High $ 26-5/8 $ 26-3/4 $ 18-7/8 $ 20
Low $ 19-1/4 $ 17-5/8 $ 15 $ 16
Close $ 22-1/2 $ 24-3/4 $ 18-1/8 $ 18-1/8
====================================================================================================================================
OTHER GENERAL DATA
Capital expenditures $ 46,163 $ 44,036 $ 22,758 $ 47,024
====================================================================================================================================
</TABLE>
Note: All information prior to 1989 has been adjusted for the effects of a
three-for-two common stock split.
All information prior to 1990 includes the effects of discontinued operations.
<PAGE> 29
<TABLE>
<CAPTION>
====================================================================================================================================
1990 1989 1988 1987 1986 1985 1984
====================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
$ 324,860 $ 308,604 $ 353,135 $ 323,590 $ 364,853 $ 378,660 $ 416,606
$ 11,267 $ 6,422 $ 11,667 $ 8,950 $ 1,544 $ 5,248 $ 5,539
$ 11,267 $ 6,422 $ 11,667 $ 8,950 $ 1,544 $ 5,248 $ 5,539
$ 1.15 $ .69 $ 1.53 $ 1.38 $ .24 $ .86 $ .93
$ 1.15 $ .69 $ 1.53 $ 1.38 $ .24 $ .86 $ .93
====================================================================================================================================
$ 113,316 $ 107,950 $ 86,256 $ 63,687 $ 58,325 $ 59,085 $ 55,291
1,800 2,450 2,450 2,850 3,000 3,150 3,300
82,835 86,188 53,203 54,589 42,286 24,690 25,606
- ------------------------------------------------------------------------------------------------------------------------------------
$ 197,951 $ 196,588 $ 141,909 $ 121,126 $ 103,611 $ 86,925 $ 84,197
- ------------------------------------------------------------------------------------------------------------------------------------
$ 326,350 $ 294,614 $ 260,560 $ 237,445 $ 211,055 $ 191,524 $ 187,790
- ------------------------------------------------------------------------------------------------------------------------------------
$ 250,983 $ 238,329 $ 206,230 $ 191,099 $ 170,952 $ 150,544 $ 135,562
====================================================================================================================================
$ .94 $ .88 $ .827 $ .76 $ .72 $ .693 $ .613
$ .895 $ .843 $ .777 $ .73 $ .70 $ .653 $ .593
$ 11.48 $ 11.13 $ 10.80 $ 9.73 $ 9.02 $ 9.45 $ 9.22
157 190 147 163 140 97 92
5.2 4.2 5.2 4.8 5.7 7.6 7.2
10.0 6.0 15.6 14.7 2.6 9.2 10.3
15.7 30.6 10.4 11.5 52.6 10.6 9.1
9,872 9,695 7,989 6,544 6,467 6,253 5,996
$ 21-1/2 $ 24-3/8 $ 16-1/4 $ 16-1/2 $ 14-3/8 $ 10-3/4 $ 8-7/8
$ 16 $ 15-3/8 $ 11-3/8 $ 12-1/2 $ 9 $ 7-7/8 $ 6-3/4
$ 18 $ 21-1/8 $ 15-7/8 $ 15-7/8 $ 12-5/8 $ 9-1/8 $ 8-1/2
====================================================================================================================================
$ 37,335 $ 54,474 $ 39,260 $ 40,139 $ 39,688 $ 29,182 $ 16,021
====================================================================================================================================
</TABLE>
<PAGE> 30
Selected Operating Data
<TABLE>
<CAPTION>
Energen Corporation and Subsidiaries
====================================================================================================================================
Years ended September 30,
(dollars in thousands) 1994 1993 1992 1991
====================================================================================================================================
<S> <C> <C> <C> <C>
NATURAL GAS DISTRIBUTION
Gas sold and transported (MMcf)
Residential 31,254 30,957 29,119 26,262
Commercial and industrial--small 13,536 13,853 13,860 14,837
Commercial and industrial--large 106 282 2,654 3,411
Transportation 52,635 49,346 46,235 41,447
- ------------------------------------------------------------------------------------------------------------------------------------
Total 97,531 94,438 91,868 85,957
- ------------------------------------------------------------------------------------------------------------------------------------
Revenues from gas sold and transported
Residential $229,019 $216,587 $198,676 $195,250
Commercial and industrial--small 84,443 83,069 78,799 84,260
Commercial and industrial--large 790 1,223 6,501 8,916
Transportation 29,321 27,382 25,089 22,890
Other 1,064 2,299 1,661 (2,188)
- ------------------------------------------------------------------------------------------------------------------------------------
Total $344,637 $330,560 $310,726 $309,128
- ------------------------------------------------------------------------------------------------------------------------------------
Average number of customers
Residential 402,531 395,057 387,871 382,747
Commercial and industrial--small 32,563 32,269 31,732 31,432
Commercial and industrial--large 43 46 41 39
- ------------------------------------------------------------------------------------------------------------------------------------
Total 435,137 427,372 419,644 414,218
- ------------------------------------------------------------------------------------------------------------------------------------
Degree days (systemwide)
39-year moving average 2,590 2,590 2,590 2,590
Actual for year 2,636 2,624 2,434 2,017
Ratio of actual to 39-year average (%) 101.8 101.3 94.0 77.9
====================================================================================================================================
OIL AND GAS PRODUCTION
Operating revenues $ 25,211 $ 19,887 $ 15,718 $ 12,661
Coalbed methane proved reserves (MMcf) 26,712 34,109 34,306 61,314
Conventional proved reserves (MMcf)* 42,261 40,923 19,041 14,369
Oil and gas produced (MMcf)* 10,316 7,468 7,287 6,455
====================================================================================================================================
OTHER ACTIVITIES
Operating revenues $ 15,401 $ 14,926 $ 15,099 $ 13,951
Operating income $ 1,594 $ 929 $ 2,009 $ 1,395
Property, plant and equipment, net $ 1,977 $ 6,273 $ 6,797 $ 7,098
====================================================================================================================================
</TABLE>
* Oil expressed in natural gas equivalents
<PAGE> 31
<TABLE>
<CAPTION>
====================================================================================================================================
1990 1989 1988 1987 1986 1985 1984
====================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
28,653 27,210 28,636 27,365 25,373 26,314 29,300
16,581 17,946 21,806 18,482 22,337 22,620 24,168
4,786 9,494 13,026 8,902 20,877 18,365 23,180
39,117 34,447 28,730 26,895 6,636 3,876 --
- ------------------------------------------------------------------------------------------------------------------------------------
89,137 89,097 92,198 81,644 75,223 71,175 76,648
- ------------------------------------------------------------------------------------------------------------------------------------
$188,168 $170,302 $190,836 $181,007 $165,160 $165,034 $177,261
85,588 85,477 104,420 93,242 112,580 119,290 124,963
13,596 25,000 37,923 24,982 77,989 87,134 108,932
22,734 19,574 15,158 17,871 3,748 1,802 --
873 731 689 679 648 507 1,247
- ------------------------------------------------------------------------------------------------------------------------------------
$310,959 $301,084 $349,026 $317,781 $360,125 $373,767 $412,403
- ------------------------------------------------------------------------------------------------------------------------------------
379,362 365,572 358,872 350,712 341,406 334,418 329,237
31,565 30,492 29,717 29,007 28,318 27,817 27,512
42 42 37 34 32 30 34
- ------------------------------------------------------------------------------------------------------------------------------------
410,969 396,106 388,626 379,753 369,756 362,265 356,783
- ------------------------------------------------------------------------------------------------------------------------------------
2,590 2,585 2,585 2,585 2,585 2,590 2,591
2,378 2,383 2,592 2,523 2,345 2,410 2,868
91.8 92.2 100.3 97.6 90.7 93.1 110.7
====================================================================================================================================
$ 12,983 $ 13,469 $ 13,034 $ 9,536 $ 8,163 $ 7,833 $ 4,203
44,881 17,384 8,783 9,450 3,594 -- --
14,626 14,060 7,772 8,985 10,796 12,136 10,375
5,434 5,534 5,540 3,975 2,926 2,374 1,199
====================================================================================================================================
$ 13,372 $ 5,962 $ 3,345 $ 3,843 $ 734 $ 578 $ 93
$ 1,890 $ (94) $ 1,324 $ 1,690 $ 319 $ 317 $ 36
$ 7,754 $ 9,004 $ 9,814 $ 5,833 $ 5,581 $ 44 $ 84
====================================================================================================================================
</TABLE>
<PAGE> 1
EXHIBIT 21
SUBSIDIARIES OF ENERGEN CORPORATION
Alabama Gas Corporation
Taurus Exploration, Inc.
Taurus Exploration USA, Inc.
Basin Pipeline Corp
American Heat Tech, Inc.
Graves Well Drilling Company, Inc.
EGN Services, Inc.
Midtown NGV, Inc.
<PAGE> 1
EXHIBIT 23(a)
CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
We consent to the incorporation by reference in the registration statements of
Energen Corporation on Forms S-8 and S-3 (File No. 2-89855), Form S-3 (File
No. 33-41997) and Forms S-8 (File No. 33-27869, File No. 33-46641, File No.
33-48504, and File No. 33-48505) of our report, which includes an explanatory
paragraph regarding the Company's change in method of accounting for certain
other postretirement benefits and income taxes, dated October 26, 1994, on our
audits of the consolidated financial statements of Energen Corporation as of
September 30, 1994 and 1993, and for the years ended September 30, 1994, 1993,
and 1992, which report is incorporated by reference in this Annual Report on
Form 10-K.
Coopers and Lybrand L.L.P.
Birmingham, Alabama
December 28, 1994
<PAGE> 1
EXHIBIT 23(b)
CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
We consent to the incorporation by reference in the registration statement of
Alabama Gas Corporation on Form S-3 (File No. 33-70466), of our report, which
includes an explanatory paragraph regarding the change in method of accounting
for certain other postretirement benefits and income taxes, dated October 26,
1994, on our audits of the financial statements and financial statement
schedules of Alabama Gas Corporation as of September 30, 1994 and 1993, and for
the years ended September 30, 1994, 1993, and 1992, which report is included in
this Annual Report on Form 10-K.
Coopers and Lybrand L.L.P.
Birmingham, Alabama
December 28, 1994
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
EXHIBIT 27.1
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
FINANCIAL STATEMENTS OF ALABAMA GAS CORPORATION FOR THE YEAR ENDED
SEPTEMBER 30, 1994, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000003146
<NAME> ALABAMA GAS CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1994
<PERIOD-START> OCT-01-1993
<PERIOD-END> SEP-30-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 233,266
<OTHER-PROPERTY-AND-INVEST> 183
<TOTAL-CURRENT-ASSETS> 66,382
<TOTAL-DEFERRED-CHARGES> 9,074
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 308,905
<COMMON> 20
<CAPITAL-SURPLUS-PAID-IN> 34,484
<RETAINED-EARNINGS> 81,087
<TOTAL-COMMON-STOCKHOLDERS-EQ> 115,591
0
0
<LONG-TERM-DEBT-NET> 84,391
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 4,000
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 2,823
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 102,100
<TOT-CAPITALIZATION-AND-LIAB> 308,905
<GROSS-OPERATING-REVENUE> 344,637
<INCOME-TAX-EXPENSE> 7,718
<OTHER-OPERATING-EXPENSES> 314,620
<TOTAL-OPERATING-EXPENSES> 322,338
<OPERATING-INCOME-LOSS> 22,299
<OTHER-INCOME-NET> 917
<INCOME-BEFORE-INTEREST-EXPEN> 23,216
<TOTAL-INTEREST-EXPENSE> 8,320
<NET-INCOME> 14,896
0
<EARNINGS-AVAILABLE-FOR-COMM> 14,896
<COMMON-STOCK-DIVIDENDS> 8,695
<TOTAL-INTEREST-ON-BONDS> 6,008
<CASH-FLOW-OPERATIONS> 21,177
<EPS-PRIMARY> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1>Earnings per share is calculated for Energen Corporation (parent company of
Alagasco) and is not calculated for Alagasco separately, as amount would
not be meaningful.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
EXHIBIT 27.2
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FORM THE
FINANCIAL STATEMENTS OF ENERGEN CORPORATION FOR THE YEAR ENDED SEPTEMBER
30, 1994, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<CIK> 0000277595
<NAME> ENERGEN CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1994
<PERIOD-START> OCT-01-1993
<PERIOD-END> SEP-30-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 233,266
<OTHER-PROPERTY-AND-INVEST> 53,916
<TOTAL-CURRENT-ASSETS> 109,091
<TOTAL-DEFERRED-CHARGES> 11,130
<OTHER-ASSETS> 3,911
<TOTAL-ASSETS> 411,314
<COMMON> 109
<CAPITAL-SURPLUS-PAID-IN> 83,875
<RETAINED-EARNINGS> 83,042
<TOTAL-COMMON-STOCKHOLDERS-EQ> 167,026
0
0
<LONG-TERM-DEBT-NET> 118,302
<SHORT-TERM-NOTES> 6,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 10,123
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 109,863
<TOT-CAPITALIZATION-AND-LIAB> 411,314
<GROSS-OPERATING-REVENUE> 377,073
<INCOME-TAX-EXPENSE> 6,611
<OTHER-OPERATING-EXPENSES> 341,165
<TOTAL-OPERATING-EXPENSES> 347,776
<OPERATING-INCOME-LOSS> 29,297
<OTHER-INCOME-NET> 5,799
<INCOME-BEFORE-INTEREST-EXPEN> 35,096
<TOTAL-INTEREST-EXPENSE> (11,345)
<NET-INCOME> 23,751
0
<EARNINGS-AVAILABLE-FOR-COMM> 23,751
<COMMON-STOCK-DIVIDENDS> (11,749)
<TOTAL-INTEREST-ON-BONDS> 8,566
<CASH-FLOW-OPERATIONS> 34,343
<EPS-PRIMARY> 2.19
<EPS-DILUTED> 2.19
</TABLE>
